ConocoPhillips is an international energy company and is considered the third largest US oil company.
2016
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
For the transition period from to
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
(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
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.
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).
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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $43.60, was $54.0 billion.
The registrant had 1,235,832,469 shares of common stock outstanding at January 31, 2017.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 16, 2017 (Part III)
TABLE OF CONTENTS
Item
1 and 2.
Business and Properties
Corporate Structure
Segment and Geographic Information
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Competition
General
1A.
Risk Factors
1B.
Unresolved Staff Comments
3.
Legal Proceedings
4.
Mine Safety Disclosures
Executive Officers of the Registrant
PART II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
6.
Selected Financial Data
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
7A.
Quantitative and Qualitative Disclosures About Market Risk
8.
Financial Statements and Supplementary Data
9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A.
Controls and Procedures
9B.
Other Information
PART III
10.
Directors, Executive Officers and Corporate Governance
11.
Executive Compensation
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
13.
Certain Relationships and Related Transactions, and Director Independence
14.
Principal Accounting Fees and Services
PART IV
15.
Exhibits, Financial Statement Schedules
Signatures
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 72.
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 the applicable periods presented. For additional information on the sale of our Nigeria business, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.
Headquartered in Houston, Texas, we have operations and activities in 17 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 tight oil and oil sands assets; lower-risk conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects.
At December 31, 2016, ConocoPhillips employed approximately 13,300 people worldwide.
In November 2016, we announced our planned $5 billion to $8 billion asset disposition program, primarily associated with North American natural gas assets, over the next two years. For additional information on asset sales, see the “Outlook” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
1
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 24—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, 2016, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.
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:
2
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 81 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.
Net Proved Reserves at December 31
Crude oil
Consolidated operations
Equity affiliates
Total Crude Oil
Natural gas liquids
Total Natural Gas Liquids
Natural gas
Total Natural Gas
Bitumen
Total Bitumen
Total consolidated operations
Total equity affiliates
Total company
Total production, including Libya, of 1,569 thousand barrels of oil equivalent per day (MBOED) decreased 1 percent in 2016 compared with 2015. The decrease in total average production primarily resulted from normal field decline and the loss of 72 MBOED mainly attributable to the 2015 dispositions of several non-core assets in the Lower 48, western Canada and the sale of our interest in the Polar Lights Company in Russia. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Western North Slope in Alaska; the Kebabangan gas field in Malaysia; and the Greater Ekofisk Area in Norway. Improved drilling and well performance in Canada, Norway, the Lower 48, and China, as well as lower unplanned downtime in the Lower 48 also partly offset the decrease in production. Assets sold in 2016 produced 27 MBOED and 36 MBOED in 2016 and 2015, respectively.
Our worldwide annual average realized price was $28.35 per BOE in 2016, a decrease of 17 percent compared with $34.34 per BOE in 2015, which reflected lower average realized prices across all commodities. Our worldwide annual average crude oil price decreased 15 percent in 2016, from $48.26 per barrel in 2015 to $40.86 per barrel in 2016. Additionally, our worldwide annual average natural gas liquids prices decreased 6 percent, from $17.79 per barrel in 2015 to $16.68 per barrel in 2016. Our worldwide annual average natural gas price decreased 24 percent, from $3.96 per MCF in 2015 to $3.00 per MCF in 2016. Average annual bitumen prices also decreased 18 percent, from $18.72 per barrel in 2015 to $15.27 per barrel in 2016.
3
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 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, federal and fee exploration leases, with approximately 0.5 million net undeveloped acres at year-end 2016. Following the impairment of our Chukchi Sea leases in the fourth quarter of 2015, we surrendered 0.3 million acres in the Chukchi Sea in May 2016. In 2016, Alaska operations contributed 19 percent of our worldwide liquids production and less than 1 percent of our natural gas production.
Average Daily Net Production
Greater Prudhoe Area
Greater Kuparuk Area
Western North Slope
Cook Inlet Area
Total Alaska
*Thousands of barrels per day.
**Millions of cubic feet per day.
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.
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.
Drill Site 2S, in the southwestern area of the Kuparuk Field, was sanctioned in October 2014. First oil was achieved in October 2015, and completion of the first phase of the project was achieved in 2016.
The 1H Northeast West Sak (NEWS) oil development targeting the West Sak reservoir in the Kuparuk River Unit, was sanctioned in March 2015. First production is anticipated in 2018.
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 October 2015, first oil was achieved at Alpine West CD5, a new drill site which extends the Alpine reservoir west into the National Petroleum Reserve-Alaska (NPR-A). During the year, we approved drilling an additional 18 wells, bringing CD5 up to its full permit capacity.
4
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 and #2, with expected first oil in 2018 and 2020, respectively.
We have a 100 percent interest and are the operator of the Kenai LNG Facility in the Cook Inlet Area. 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. In February 2016, our export license was renewed for an additional two years. However, there was no LNG export program in 2016 due to market conditions. We are currently marketing this facility.
In April and October 2016, we sold our interests in the Beluga River Unit natural gas field and the North Cook Inlet Unit, respectively, both in the Cook Inlet Area. The full-year 2016 production from the assets sold was 2 MBOED.
Point Thomson
We own a 4.9 percent interest in the Point Thomson Unit, which is located approximately 60 miles east of Prudhoe Bay. An Initial Production System (IPS) was brought online in April 2016, and achieved full production of 400 BOED net of condensate in December.
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 (collectively, the “AKLNG co-venturers”), 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 September 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. Given AGDC’s intention to continue efforts to advance a North Slope Gas project, the AKLNG co-venturers executed certain agreements to enhance AGDC’s ability to do so. We remain supportive of AGDC’s efforts to progress a project.
Exploration
In 2016, we drilled three exploration wells in the NPR-A. Two of these wells, Tinmiaq 2 and 6, form the Willow discovery, which is located in the northeast portion of the NPR-A. The third exploration well was recorded to dry hole expense in the fourth quarter of 2016. Appraisal of the Willow discovery commenced in January 2017 with the acquisition of 3-D seismic. In a follow-up to the Willow discovery, we were successful in December’s state and federal lease sales on the Western North Slope, where we were the high bidder on 139 tracts for a total of 737,252 gross acres.
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.
5
LOWER 48
The Lower 48 segment consists of operations located in the U.S. Lower 48 states and the Gulf of Mexico. The Lower 48 business is organized within three regions covering the Gulf Coast, Mid-Continent and Rockies. As a result of tight oil opportunities, we have directed our investments toward certain shorter cycle time, low cost-of-supply plays. In July 2015, we announced our plan to reduce future deepwater exploration spending. We have subsequently terminated our Gulf of Mexico deepwater drillship contracts. We hold 12.4 million net onshore and offshore acres in the Lower 48. In 2016, the Lower 48 contributed 30 percent of our worldwide liquids production and 32 percent of our natural gas production.
Eagle Ford
Gulf of Mexico
Gulf Coast—Other
Total Gulf Coast
Permian
Barnett
Anadarko Basin
Total Mid-Continent
Bakken
Wyoming/Uinta
Niobrara
San Juan
Total Rockies
Total U.S. Lower 48
Onshore
We hold 12.3 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 2.6 million net acres in the following areas:
6
The majority of our 2016 onshore production originated from the Eagle Ford, San Juan, Permian and Bakken. Onshore activities in 2016 were centered mostly on continued development of emerging and existing assets, with an emphasis on areas with low cost of supply, particularly in growing unconventional plays. The 2016 drilling activity levels declined relative to 2015 due to reduced capital spending in the low commodity price environment. Our major focus areas in 2016 included the following:
In 2015, we completed the sale of certain non-core assets in East Texas and North Louisiana and South Texas. Production from the assets sold was 33 MBOED, approximately 6 percent of the total Lower 48 segment production in 2015. In the second quarter of 2016, we completed the sale of certain non-core assets in the Delaware basin. The full-year 2016 production from the assets sold was 1 MBOED.
At year-end 2016, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:
At December 31, 2016, we held approximately 73,000 net acres in the deepwater Gulf of Mexico.
We own a 30 percent nonoperated working interest in the Shenandoah discovery, which was announced in 2009, and had a net book value of $286 million at December 31, 2016. Appraisal drilling continued in 2016 with the fifth Shenandoah well reaching total depth in the third quarter. In February 2017, the sixth Shenandoah well, Shenandoah WR52-3, reached total depth. Drilling of a sidetrack well from Shenandoah WR52-3 also commenced in February.
7
As part of our continued phased exit from deepwater exploration, in 2016, we decided not to pursue further development of the nonoperated Gibson and Tiber wells, collectively known as the Tigris project. Accordingly, we recorded dry hole expenses for previously suspended Gibson and Tiber wells, and impairment charges for the applicable leaseholds.
We recorded dry hole and associated leasehold impairment expense in the first quarter of 2016 for the Melmar exploration well.
In 2016, we drilled a total of five operated unconventional wells, primarily in the Eagle Ford. Our onshore focus areas include the Permian in the Delaware Basin and the Niobrara in the Denver-Julesburg Basin, as well as several emerging plays. We continue to assess and appraise these and other unconventional opportunities.
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 conditions were satisfied in 2014. Our terminal regasification capacity was reduced to zero on July 1, 2016. For additional information, see Note 7—Investments, Loans and Long-Term Receivables, 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 $260 million at December 31, 2016. 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. As a result, we are evaluating opportunities to optimize the value of the terminal facilities.
Greater Northern Iron Ore Properties Trust
We held the reversionary interest in the Greater Northern Iron Ore Properties trust (the Trust), a grantor trust that owns mineral and surface interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminated on April 6, 2015. On November 3, 2016, the end of the wind-down period, documents memorializing our ownership of certain Trust property, including all the Trust’s mineral properties and active leases, were delivered to us. The $144 million fair value of the Trust’s net assets transferred to us and a gain of $88 million were both recorded in the fourth quarter of 2016. On December 8, 2016, we closed on a sale of the Trust’s and certain other assets for net proceeds of $148 million. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
Other
8
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 2016, operations in Canada contributed 23 percent of our worldwide liquids production and 14 percent of our natural gas production.
Western Canada
Surmont
Foster Creek
Christina Lake
Total Canada
Our operations in western Canada extend across Alberta and British Columbia. We operate or have ownership interests in approximately 30 natural gas processing plants in the region, and, as of December 31, 2016, held leasehold rights in 3.1 million net acres in western Canada. Our investments in 2016 were focused mainly on opportunities in the following three core development areas:
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 0.9 million net acres of land in the Athabasca Region of northeastern Alberta.
9
Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. With the achievement of first production at Phase G in 2016, there are seven producing phases at Foster Creek, Phases A through G. Net production at Foster Creek increased approximately 5 MBOED in 2016.
Christina Lake is located approximately 75 miles south of Fort McMurray, Alberta. Christina Lake Phase F achieved first production in 2016. There are now six producing phases at Christina Lake. Construction on Phase G, which has a design capacity of 50 MBOED gross, will resume in 2017 after being deferred since 2014. First production from Phase G is expected in the second half of 2019. Net production at Christina Lake increased approximately 6 MBOED in 2016.
Narrows Lake Phase A, was sanctioned in late 2012 and is expected to have 45 MBOED of gross design production capacity. Construction has been deferred, however, we expect to progress engineering activity in 2017.
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 unconventional plays in western Canada.
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. In 2016, we recorded dry hole expenses associated with two wells in the Shelburne Basin, and an impairment charge for the undeveloped leasehold costs. Other related costs have been accrued.
In August 2016, we sold our Newfoundland Partnership, which held a 30 percent nonoperated interest in the exploration license in the Flemish Pass Basin, offshore Newfoundland.
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 2016, we completed a lease swap for unproved lands in the Blueberry area and continued to drill exploration and appraisal wells in the Montney play, which extends from British Columbia into Alberta. Full-year 2016 production from the assets swapped was 5 MBOED. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
10
EUROPE AND NORTH AFRICA
The Europe and North Africa segment consists of operations and exploration activities in Norway, the United Kingdom and Libya. In 2016, operations in Europe and North Africa contributed 14 percent of our worldwide liquids production and 12 percent of natural gas production.
Norway
Greater Ekofisk Area
Alvheim
Heidrun
Total Norway
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. Ekofisk South achieved first production in 2013, while Eldfisk II achieved startup in January 2015. Continued development drilling in the Greater Ekofisk Area 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 Scottish Area Gas Evacuation (SAGE) terminal at St. Fergus, Scotland, through the SAGE pipeline.
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 exported to the Continent via gas processing terminals in Norway, while the remainder is exported for use as feedstock in a methanol plant in Norway, in which we own an 18 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 2018.
We participated in two nonoperated exploration wells in the Oseberg and Alvheim areas. Both wells were discoveries and are currently undergoing evaluation. We were awarded three licenses in 2016, including the PL845 and PL782SB, both with interests of 40 percent, and PL859, which has a 15 percent interest.
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.
11
United Kingdom
GasMMCFD
Britannia
Britannia Satellites
J-Area
Southern North Sea
East Irish Sea
Total United Kingdom
* Includes the Chevron-operated Alder field, ConocoPhillips equity 26.3%.
Britannia is one of the largest natural gas and condensate fields in the North Sea. We assumed operatorship of Britannia in August 2015, following the acquisition of third party equity in Britannia Operator Limited, which is now wholly owned by ConocoPhillips. 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. Project startups for the Brodgar H3 susbsea well, and Enochdhu, a single well tie back to Callanish, were achieved in 2015. First gas was achieved from Alder, a single well tie back to Britannia, in the fourth quarter of 2016.
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.
We have various ownership interests in several producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Decommissioning activity in the Southern North Sea is ongoing, with final production from the Viking transportation system and associated satellites achieved in early 2016. 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 2018.
In 2016, we recorded dry hole expense for the fully-owned Temple Wood well in the Greater Britannia Area, which was permanently plugged and abandoned.
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.
12
Greenland
In the first quarter of 2016, we completed the process to assign our participating interest in the nonoperated Avinngaq license. Additionally, our operated Qamut license expired on December 31, 2016. Our work program in Greenland is complete, pending certain approvals.
Libya
Waha Concession
Total Libya
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 was shut in again. Production resumed in Libya in October 2016, with three crude liftings from Es Sider in January 2017. We expect a gradual ramp-up in activity.
ASIA PACIFIC AND MIDDLE EAST
The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia and Australia; producing operations in Qatar and Timor-Leste; and exploration activities in Brunei. In 2016, operations in the Asia Pacific and Middle East segment contributed 14 percent of our worldwide liquids production and 42 percent of natural gas production.
Australia and Timor Sea
Gas
MMCFD
Australia Pacific LNG
Bayu-Undan
Athena/Perseus
Total Australia and Timor Sea
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 coalbed methane into LNG. Natural gas is sold to domestic customers, while LNG is exported. 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.
13
Two fully subscribed 4.5 million tonnes-per-year LNG trains have been completed. Approximately 3,900 net wells are ultimately envisioned 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 LNG sales continued throughout the year. Train 1 LNG is being sold to Sinopec under a 20-year sales agreement for up to 4.3 million metric tonnes of LNG per year. APLNG Train 2 achieved first production in the third quarter of 2016. The LNG from Train 2 is being sold to Sinopec under a 20-year sales agreement for an additional 3.3 million metric tonnes of LNG per year through 2035, 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, of which $8.5 billion had been drawn from the facility at December 31, 2016. 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. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. For additional information, see Note 4—Variable Interest Entities (VIEs), Note 7—Investments, Loans and Long-Term Receivables, and Note 12—Guarantees, in the Notes to Consolidated Financial Statements.
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 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 2016, we sold 168 billion gross cubic feet of LNG primarily 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. The first subsea horizontal well was tied back to the existing drilling, production and processing platform, and commenced production in 2015, while the second well was suspended due to insufficient deliverability to the platform. A continuation of the Bayu-Undan Phase Three Development is being evaluated with the front-end engineering and design phase approaching completion. The current premise is that drilling of one subsea and two platform wells will commence in 2018, pending internal, joint venture and regulatory approval.
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 Singapore in June 2014 under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. We reached a settlement with the Timor-Leste government on these disputes in 2016.
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 April 2016, the Timor-Leste Government initiated conciliation under the United Nations Convention of the Law of the Sea (UNCLOS) in an attempt to negotiate permanent maritime boundaries. The conciliation is on-going between the governments of Timor-Leste and Australia.
14
The UNCLOS conciliation 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.
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 completed, 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 new 3-D seismic survey was completed over the Barossa and Caldita Field area between August and October 2016. Drilling of the next appraisal well, Barossa-5, commenced in January 2017. Drilling of a subsequent well, Barossa-6, may follow dependent on the results of Barossa-5.
Indonesia
MBD
MBOED
South Natuna Sea Block B
South Sumatra
Total Indonesia
We operate three production sharing contracts (PSCs) 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. In 2016, we sold our 40 percent working interest in the offshore South Natuna Sea Block B PSC, which had 3 producing oil fields, and 16 natural gas fields in various stages of development. Full-year 2016 production from South Natuna Sea Block B was 19 MBOED.
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.
During 2016, we relinquished our 80 percent interest in the Warim Block PSC. 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 2 million gross acres.
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.
15
China
Penglai
Panyu
Total China
The Penglai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase 1 development of the Penglai 19-3 Field began in 2002. Phase 2 included six additional wellhead platforms and an FPSO vessel, and was fully operational by 2009.
As part of further development of the Penglai 19-9 Field, a new wellhead platform, which adds up to 62 wells, is progressing according to schedule, with two wells completed and brought online in December 2016.
We sanctioned the Penglai 19-3/19-9 Phase 3 Project in December 2015. This project will consist of three new wellhead platforms and a central processing platform. First oil from Phase 3 is expected in 2018.
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 and 5-1 will expire in 2018, and the production period for Panyu 11-6 will expire in 2022.
In 2016, we participated in a successful appraisal well in the Penglai fields, which will support future development plans.
Malaysia
Siakap North-Petai
Gumusut
KBB
Total Malaysia
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, deepwater Block 3E, Block SK313 and Block WL4-00 are located off the eastern Malaysian state of Sarawak.
16
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 and reached its estimated net annual peak production of 5 MBOED in 2015.
First production from Malikai was achieved in December 2016, with estimated net annual peak production of 18 MBOED expected in 2019. The Limbayong-1 well was drilled in 2002 and resulted in a gas discovery. The Limbayong-2 appraisal well was drilled in 2013 and resulted in an oil discovery. Development options are being evaluated. We own a 35 percent interest in the Malikai, Limbayong and Pisagan discoveries.
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 net annual peak production of 36 MBOED reached in 2016. Unitization of the Gumusut Field with Brunei was recorded in 2014 and reduced our ownership interest from 33 percent to an initial 29 percent. A final ownership split is expected to be agreed in 2017. Gumusut Phase 2 infill drilling is planned to start in 2018.
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. Estimated net annual peak production of 26 MBOED is expected in 2018. Development options for the Kamunsu East gas field are being evaluated.
We own a 50 percent operated interest in deepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic processing was completed in 2015. The Langsat-1 exploration well was spud in February 2017.
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 approximately 629,000 gross acres, in January 2017. We have a 50 percent operated interest in this block which includes the Salam-1 oil discovery. A new 3-D seismic survey is planned for 2017 with drilling of an appraisal well expected in 2018.
Brunei
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, with natural gas discovered at the Kelidang NE-1 and Keratau-1 wells in 2013 and at the Keratau SW-1 well in 2015. Evaluation of the results is ongoing.
Myanmar
In 2014, we were awarded deepwater Block AD-10 in the 2013 Myanmar offshore oil and gas bidding round. We signed the PSC in the second quarter of 2015. In 2016, we assigned our participating interest to the operator.
17
Qatar
QG3
Total Qatar
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. In 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal.
Angola
Our 50 percent operated interest in Block 36 and our 30 percent operated interest in Block 37, both of which are located in Angola’s subsalt play trend, expired on December 31, 2016. In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we will recognize a before-tax charge of $43 million net in the first quarter of 2017.
Senegal
On October 28, 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for information regarding our asset dispositions.
Colombia
Unconventional 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. Production tests and appraisal of the area are ongoing.
We hold 70 percent nonoperated interests in the deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. The relinquishment of the Santa Isabel Block was accepted and the parties are in the process of documenting such relinquishment.
18
The exploration and production contract for the VMM27 Block, in the Middle Magdalena Basin, where we held a 30 percent nonoperated interest, has been fully terminated. We also hold a 30 percent nonoperated interest in the VMM28 Block, in the Middle Magdalena Basin, where we are in the process of terminating with the relevant parties and the regulatory agency.
Chile
In June 2016, we entered into an agreement with Empresa Nacional Del Petroleo (ENAP) to acquire an additional 44 percent participating interest in the onshore Coiron Block located in the Magallanes Basin in southern Chile where we already had 5 percent participation. Assignment of the additional participating interest to ConocoPhillips was approved by the Chilean Ministry of Energy and the Controller General of Chile. ENAP holds the remaining 51 percent participating interest and will continue to be the operator.
In 2016, two exploration wells were successfully drilled, logged and cored. In 2017, we will continue to explore and appraise the Coiron Block.
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). The ICSID Tribunal 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. In October 2016, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware against PDVSA, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors. For additional information, see Note 13—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. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and its co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set. For additional information, see Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Discontinued Operations
See Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements, for information regarding our discontinued operations.
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.
19
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
We are a founding member of the Marine Well Containment Company (MWCC), a non-profit organization formed in 2010, which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC’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 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.
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.
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 U.K., 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 U.S. 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.
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 25 LNG trains around the world, with feasibility studies ongoing for additional trains.
20
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, 2016. No difference exists between our estimated total proved reserves for year-end 2015 and year-end 2014, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2016.
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 2.0 trillion cubic feet of natural gas, including approximately 363 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 180 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2027. 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 5, 2016, 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 2015. 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 2016, we held a total of 714 active patents in 49 countries worldwide, including 286 active U.S. patents. During 2016, we received 37 patents in the United States and 66 foreign patents. Our products and processes generated licensing revenues of $128 million in 2016. 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 $116 million, $222 million and $263 million in 2016, 2015 and 2014, 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 process and occupational safety. In support of the goal of zero incidents, HSE milestones and criteria are established annually to drive strong safety performance.
21
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 63 through 66 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2016 and those expected for 2017 and 2018.
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.
22
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. Globally, prices for crude oil, bitumen, natural gas, natural gas liquids and LNG have experienced significant declines from their historic levels during 2013 and 2014, with excess of supply relative to global demand leading to global inventory builds. Total average annual prices in 2016 for Brent crude oil, WTI crude oil, Henry Hub natural gas and our realized natural gas liquids all decreased by more than 5 percent when compared with 2015. In the fourth quarter of 2016, Brent crude oil, WTI crude oil, Henry Hub natural gas and our realized natural gas liquids prices all increased, compared with the same period of 2015. Given volatility in commodity price drivers and the business environment, price trends may not continue or reverse themselves.
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 on the amount of dividends we elect to declare and pay on our common stock. Lower prices may also limit the amount of reserves we can produce economically, adversely affecting our ability to maintain our reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields.
Significant reductions in crude oil, bitumen, natural gas, natural gas liquids and LNG prices could also require us to reduce our capital expenditures or impair the carrying value of our assets. In the past two years, we recognized several impairments, which are described in Note 9—Impairments and the “APLNG” section of Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements. If commodity prices remain low relative to their historic levels, and as we continue to optimize our investments and exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets used in operations, investments in nonconsolidated entities accounted for under the equity method and unproved properties. Although it is not reasonably practicable to quantify the impact of any future impairments at this time, our results of operations could be adversely affected as a result.
Our ability to declare and pay dividends is subject to certain considerations.
Dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:
We expect to continue to pay quarterly distributions to our stockholders; however, we bear all expenses incurred by our operations, and our funds generated by operations, after deducting these expenses, may not be sufficient to cover desired levels of distributions to our stockholders. Any downward revision in our distribution could have a material adverse effect on the market price of our common stock.
23
We may need additional capital in the future, and it may not be available on acceptable terms.
We have historically relied primarily upon cash generated by our operations to fund our operations and strategy, however we have also relied from time to time on access to the debt and equity capital markets for funding. There can be no assurance that additional debt or equity financing will be available in the future on acceptable terms, or at all. Our ability to obtain additional financing will be subject to a number of factors, including market conditions, our operating performance, investor sentiment and our ability to incur additional debt in compliance with agreements governing our then-outstanding debt. If we are unable to generate sufficient funds from operations or raise additional capital, our growth could be impeded.
In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. Due to the significant decline in prices for crude oil, bitumen, natural gas, natural gas liquids and LNG, and the expectation that these prices could remain depressed in the near future, the major ratings agencies conducted a review of the oil and gas industry and downgraded our debt ratings and those of several companies operating in the industry. Any downgrade in our credit rating, could increase the cost associated with any additional indebtedness we incur.
Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business.
The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing, particularly as it relates to other companies in the oil and gas industry as a result of the recent significant declines in commodity prices. Any default by any of our counterparties may result in our inability to perform obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances.
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 cash conservation efforts we may undertake as a result of commodity price declines may further limit our ability to replace depleted reserves.
The exploration and production of oil and gas is a highly competitive industry.
The exploration and production of crude oil, bitumen, natural gas and natural gas liquids is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including to locate and obtain new sources of supply and to produce oil, bitumen, natural gas and natural gas liquids in an efficient, cost-effective manner. Some of our competitors are larger and have greater resources than we do or may be willing to incur a higher level of risk than we are willing to incur to obtain potential sources of supply. If we are not successful in our competition for new reserves, our financial condition and results of operations may be adversely affected.
24
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 or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation. In addition to changes in the quantity and value of our proved reserves, the amount of crude oil, bitumen, natural gas and natural gas liquids that can be obtained from any proved reserve may ultimately be different from those estimated prior to extraction.
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, such as limitations on greenhouse gas emissions, 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:
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. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the Paris climate conference in December 2015. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Our operations and the demand for our products could be materially impacted by the development and adoption of these technologies.
25
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 58 percent of our hydrocarbon production was derived from production outside the United States in 2016, and 55 percent of our proved reserves, as of December 31, 2016, 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. In particular, some countries where we operate lack well-developed legal systems or have not adopted clear legal and regulatory frameworks for oil and gas exploration and production. This lack of legal certainty exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations.
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.
26
We may not be able to successfully complete any disposition we elect to pursue.
From time to time, we may seek to divest portions of our business or investments that are not important to our ongoing strategic objectives. Any dispositions we undertake may involve numerous risks and uncertainties, any of which could adversely affect our results of operations or financial condition. In particular, we may not be able to successfully complete any disposition on a timeline or on terms acceptable to us, if at all, whether due to market conditions, regulatory challenges or other concerns. In addition, the reinvestment of capital from disposition proceeds may not ultimately yield investment returns in line with our internal or external expectations. Any dispositions we pursue may also result in disruption to other parts of our business, including through the diversion of resources and management attention from our ongoing business and other strategic matters, or through the disruption of relationships with our employees and key vendors. Further, in connection with any disposition, we may enter into transition services agreements or undertake indemnity or other obligations that may result in additional expenses for us.
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, terrorist attacks, sabotage, civil unrest or cyber attacks. Our operations may also 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 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. Further, our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to efficiently restore or replace affected operational components and capacity.
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.
27
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 2016, as well as matters previously reported in our 2015 Form 10-K and our first-, second- and third-quarter 2016 Form 10-Qs that were not resolved prior to the fourth quarter of 2016. 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 or have subsequently become a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.
New Matters—ConocoPhillips
A Judgment and Consent Decree was entered on December 7, 2016, by the South Central Judicial District Court in Burleigh County, North Dakota against Burlington Resources Oil & Gas Company LP and ConocoPhillips Company resolving alleged violations of the state’s air pollution control laws. The North Dakota Department of Health was the Plaintiff in this matter. The Consent Decree requires the companies to implement a specified program to inspect and repair as necessary its facilities in North Dakota and to pay a penalty of approximately $220,000.
Matters Previously Reported—Phillips 66
In October 2007, we received a Complaint from the U.S. Environmental Protection Agency (EPA) alleging violations of the Clean Water Act related to a 2006 oil spill at the Bayway Refinery and proposing a penalty of $156,000. Phillips 66 resolved this matter with the EPA in December 2016 with a settlement payment of $35,500.
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.
New Matters—Phillips 66
In October 2016, after Phillips 66 received a Notice of Intent to Sue from the Sierra Club, Phillips 66 entered into a voluntary settlement with the Illinois Environmental Protection Agency for alleged violations of wastewater requirements at the Wood River Refinery occurring in part prior to the separation. The settlement involves certain capital projects and payment of $125,000. The settlement has been filed with the Court for final approval and the Sierra Club has sought to intervene in the case to oppose the settlement. A court hearing is scheduled for March 2017.
Not applicable.
28
EXECUTIVE OFFICERS OF THE REGISTRANT
Janet L. Carrig
Senior Vice President, Legal, General Counsel and Corporate Secretary
Ellen R. DeSanctis
Vice President, Investor Relations and Communications
Matt J. Fox
Executive Vice President, Strategy, Exploration and Technology
Alan J. Hirshberg
Executive Vice President, Production, Drilling and Projects
Ryan M. Lance
Chairman of the Board of Directors and Chief Executive Officer
Andrew D. Lundquist
Senior Vice President, Government Affairs
James D. McMorran
Vice President, Human Resources, Real Estate and Facilities Services
Glenda M. Schwarz
Vice President and Controller
Don E. Wallette, Jr.
Executive Vice President, Finance, Commercial and Chief Financial Officer
*On February 15, 2017.
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 16, 2017. Set forth below is information about the executive officers.
Janet L. Carrig was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007.
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.
Matt J. Fox was appointed as Executive Vice President, Strategy, Exploration and Technology in April 2016. He previously served as the Executive Vice President, Exploration and Production, from 2012 to 2016. Prior to that, he was employed by Nexen, Inc. and served as Executive Vice President, International since 2010.
Alan J. Hirshberg was appointed Executive Vice President, Production, Drilling and Projects in April 2016. He previously served as Executive Vice President, Technology and Projects, from 2012 to 2016. Prior to that, he served as Senior Vice President, Planning and Strategy since 2010.
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.
James D. McMorran was appointed Vice President, Human Resources, Real Estate and Facilities Services in August 2015. Prior to that, he served as Manager, Compensation and Benefits, since 2004.
29
Glenda M. Schwarz was appointed Vice President and Controller in 2009.
Don E. Wallette, Jr. was appointed Executive Vice President, Finance, Commercial and Chief Financial Officer in April 2016. He previously served as Executive Vice President, Commercial, Business Development and Corporate Planning from 2012 to 2016. Prior to that, he served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.
30
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
First
Second
Third
Fourth
2015
Closing Stock Price at December 31, 2016
Closing Stock Price at January 31, 2017
Number of Stockholders of Record at January 31, 2017*
The declaration of dividends is subject to the discretion of our Board of Directors, and may be affected by various factors, including our future earnings, financial condition, capital requirements, levels of indebtedness, credit ratings and other considerations our Board of Directors deems relevant. Our Board of Directors has adopted a quarterly dividend declaration policy providing that the declaration of any dividends will be determined quarterly by the Board of Directors taking into account such factors as our business model, prevailing business conditions and our financial results and capital requirements, without a predetermined annual net income payout ratio.
On February 4, 2016, we announced that our Board of Directors approved a reduction in the quarterly dividend to $0.25 per share, compared with the previous quarterly dividend of $0.74 per share.
On January 31, 2017, we announced that our Board of Directors approved an increase in the quarterly dividend to $0.265 per share, compared with the previous quarterly dividend of $0.25 per share.
31
Issuer Purchases of Equity Securities
Period
that May Yet BePurchased Under thePlans or Programs
October 1-31, 2016
November 1-30, 2016
December 1-31, 2016
Total fourth-quarter 2016
*There were no repurchases of common stock from company employees in connection with the company’s broad-based employee incentive plans.
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock over the next three years. Repurchase of shares began in November and totaled 2,579,098 shares at a cost of $126 million, through December 31, 2016. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.
Stock Performance Graph
The following graph shows the cumulative total shareholder return (TSR) for ConocoPhillips’ common stock in each of the five years from December 31, 2011, to December 31, 2016. The graph also compares the cumulative total returns for the same five-year period with the S&P 500 Index, the performance peer group used in the prior fiscal year (the “Prior Peer Group”) and a new performance peer group for the current fiscal year (the “New Peer Group”). The Prior Peer Group consisted of BP, Chevron, ExxonMobil, Royal Dutch Shell, Total, Anadarko, Apache, BG Group plc, Devon and Occidental, weighted according to the respective peer’s stock market capitalization at the beginning of each annual period. The New Peer Group excludes BG Group plc due to its acquisition by Royal Dutch Shell in 2016 and includes Marathon Oil Corporation. The Prior Peer Group is presented for purposes of comparison. The comparison assumes $100 was invested on December 31, 2011, in ConocoPhillips stock, the S&P 500 Index, the Prior Peer Group and New Peer Group and assumes that all dividends were reinvested. The spinoff of Phillips 66 in 2012 is treated as a special dividend for the purposes of calculating TSR for ConocoPhillips. The market value of the distributed shares on the spinoff date was deemed reinvested in shares of ConocoPhillips common stock.
*Prior Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Anadarko; Apache; BG Group plc; Devon; Occidental.
**New Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Anadarko; Apache; Marathon Oil Corporation; Devon; Occidental.
32
Item 6. SELECTED FINANCIAL DATA
Sales and other operating revenues
Income (loss) from continuing operations
Per common share
Basic
Diluted
Income from discontinued operations
Net income (loss)
Net income (loss) attributable to ConocoPhillips
Total assets
Long-term debt
Joint venture acquisition obligation—long-term
Cash dividends declared per common share
Net income (loss) and Net income (loss) attributable to ConocoPhillips from 2012 to 2014 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. These factors impact the comparability of this information. For additional information on the sale of our Nigeria business, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.
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.
33
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 72.
Due to discontinued operations reporting, we believe income (loss) from continuing operations is more representative of ConocoPhillips’ earnings than overall net income (loss) attributable to ConocoPhillips. 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 3—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 17 countries. Our diverse portfolio primarily includes resource-rich North American unconventional assets and oil sands assets in Canada; lower-risk conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects. At December 31, 2016, we employed approximately 13,300 people worldwide and had total assets of $90 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”
Overview
The energy landscape remained challenged throughout 2016. Global production oversupply caused continued weakness in commodity prices in 2016 following a year of weak prices in 2015. Ongoing uncertainty around the timing and trajectory of a price recovery, coupled with tightening credit capacity across the industry, caused us to take actions early in the year to mitigate the impacts of possible prolonged weak prices. We reduced our quarterly dividend by 66 percent, to $0.25 per share, issued $3.0 billion of long-term debt, obtained a $1.6 billion three-year term loan, reduced capital expenditures and production and operating expenses, and further streamlined our portfolio.
Our capital expenditures in 2016 were $4.9 billion, a 52 percent reduction compared with 2015 and a 72 percent reduction compared with 2014. Production and operating expenses in 2016 were $5.7 billion, down 19 percent compared with 2015 and down 36 percent compared with 2014.
We also progressed our efforts to high-grade our portfolio. In 2016, we generated $1.3 billion from the disposition of certain non-core assets in our portfolio, including the offshore South Natuna Sea Block B in Indonesia and ConocoPhillips Senegal B.V., the entity that held our interest in three exploration blocks offshore Senegal. The full-year 2016 production impact of completed dispositions was 27 thousand barrels of oil equivalent per day (MBOED).
34
During 2016, we expanded our value proposition to position the company for long-term success in light of our view that commodity prices, specifically oil prices, are likely to remain lower and be more volatile in the future. Our value proposition principles, namely to maintain a strong balance sheet, grow our dividend and pursue disciplined growth, remain essentially unchanged. However, we took steps to improve our competitiveness and resilience by establishing clear priorities for allocating future cash flows.
In order, these priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares; and invest capital to grow absolute production. We outlined a 2017 to 2019 operating plan that achieves these priorities at Brent prices at or above $50 per barrel with asset sales of $5 billion to $8 billion.
We believe we have taken prudent actions to position the company for success in an environment of price uncertainty and ongoing volatility, while accomplishing significant milestones in a challenged business environment throughout 2016.
Key Operating and Financial Summary
Significant items during 2016 included the following:
Business Environment
Global oil market conditions in 2016 were challenging as the excess of supply relative to global demand led to another year of global inventory builds. Global oil prices experienced elevated levels of volatility throughout 2016 with first quarter Brent crude oil prices reaching a 10-year quarterly average low of $33.89 per barrel. Prices recovered slightly in the second and third quarters of 2016 as production growth slowed while demand continued to increase. In the fourth quarter, prices continued to trend higher, with Brent crude oil averaging $49.46 per barrel, as OPEC members and key non-OPEC producers agreed to cut production in 2017.
The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC, environmental laws, tax regulations, governmental policies and weather-related disruptions. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.
35
Financial Priorities
The financial priorities we believe will drive our success through the price cycles include:
Operational Priorities
The operational priorities we must manage well to be successful include:
In November 2016, we announced a 2017 capital budget of $5 billion.
36
In November 2016, we announced our plan to divest between $5 billion and $8 billion of assets, primarily associated with North American natural gas, over the next two years. Proceeds from the sale of assets will be directed toward the achievement of our financial priorities. We will continue to evaluate our assets to determine whether they fit our strategic direction and will optimize the portfolio as necessary, directing our capital investments to areas that align with our objectives.
Proved reserve estimates require economic production based on historical 12-month, first-of-month, average prices and current costs. Therefore, our proved reserves generally decrease as prices decline and increase as prices rise. Additionally, as we continue cash conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves. Low commodity prices and reduced capital expenditures in 2016 adversely affected our reported year-end proved reserves. In 2016, our reserve replacement was negative 194 percent. In the five years ended December 31, 2016, our reserve replacement was 35 percent. We expect our proved reserves to increase if prices rise.
Access to additional resources may become increasingly difficult as commodity prices can make projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations, national fiscal terms, 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.
37
Other Factors Affecting Profitability
Other significant factors that can affect our profitability include:
Brent crude oil prices averaged $49.46 per barrel in the fourth quarter of 2016, an increase of 13 percent compared with $43.67 per barrel in the fourth quarter of 2015. Similarly, WTI crude oil prices increased 17 percent from $42.10 per barrel in the fourth quarter of 2015 to $49.18 per barrel in the same period of 2016.
Despite the fourth quarter increase, crude oil prices were under pressure throughout 2016 due to a continued global production increase that outpaced demand growth, leading to a large observed rise in global inventory. The average Brent crude oil price decreased 17 percent, from $52.46 per barrel in 2015 to $43.69 per barrel in 2016.
Henry Hub natural gas prices averaged $2.98 per million British thermal units (MMBTU) in the fourth quarter of 2016, an increase of 31 percent compared with $2.27 per MMBTU in the fourth quarter of 2015. Natural gas prices increased in the fourth quarter due to growth in demand, coupled with declining production.
On average, Henry Hub natural gas prices decreased 8 percent from $2.67 per MMBTU in 2015 to $2.46 per MMBTU in 2016, mainly due to strong production levels and a warmer-than expected winter reducing demand below expectations. In 2016, U.S. underground gas storage inventories reached their highest levels in five years.
Our realized natural gas liquids prices averaged $21.82 per barrel in the fourth quarter of 2016, an increase of 33 percent compared with $16.42 per barrel in the same quarter of 2015.
Similar to natural gas and crude oil, our natural gas liquids prices also declined on average in 2016. Our average realized natural gas liquids prices decreased 6 percent, from $17.79 per barrel in 2015 to $16.68 per barrel in 2016, as the expansion in tight oil production boosted supplies of natural gas liquids, resulting in continued downward pressure on natural gas liquids prices in the United States.
38
Declining global crude oil prices resulted in the Western Canada Select benchmark price experiencing a 17 percent decline, from $35.21 per barrel in 2015 to $29.36 per barrel in 2016. Consequently, our realized bitumen price experienced a decrease relative to 2015 price levels. Our realized bitumen price was $15.27 per barrel in 2016, a decrease of 18 percent compared with $18.72 per barrel in the same period of 2015.
Our worldwide annual average realized price was $28.35 per barrel of oil equivalent (BOE) in 2016, a decrease of 17 percent compared with $34.34 per BOE in 2015. The reduction in the prices reflects lower average realized prices across all commodities.
In recent years, the use of hydraulic fracturing and horizontal drilling in tight oil 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 tight oil 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 asset impairments might be possible.
39
Outlook
Full-year 2017 production is expected to be 1,540 to 1,570 MBOED. This results in flat to 2 percent growth compared with full-year 2016 production of 1,540 MBOED when adjusted for 2016 dispositions of 27 MBOED. First-quarter 2017 production is expected to be 1,540 to 1,580 MBOED. Production guidance for 2017 excludes Libya and the impact of future dispositions.
In line with our strategic objectives, we are currently marketing certain non-core assets primarily associated with North American natural gas. We expect to generate $5 billion to $8 billion in proceeds over the next two years from asset sales.
Operating Segments
We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, 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, 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.
40
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s income (loss) from continuing operations by business segment follows:
Corporate and Other
2016 vs. 2015
Losses for ConocoPhillips decreased 19 percent in 2016. The decrease was mainly due to:
The decrease in losses was partly offset by:
41
2015 vs. 2014
Earnings for ConocoPhillips decreased 175 percent in 2015. The decrease was mainly due to lower commodity prices.
In addition, earnings were negatively impacted by:
These reductions to earnings were partly offset by higher sales volumes, lower production taxes due to reduced commodity prices, lower operating expenses, a $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in the first quarter of 2015, the absence of a $540 million after-tax loss resulting from the Freeport LNG termination agreement, gain on sale of assets, and higher licensing revenue.
Income Statement Analysis
Sales and other operating revenues decreased 20 percent in 2016, mainly as a result of lower prices across all commodities. Additionally, sales and other operating revenues decreased due to lower natural gas, crude oil and natural gas liquids sales volumes, mainly from dispositions and field decline, partly offset by increased bitumen sales volumes.
Equity in earnings of affiliates decreased 92 percent in 2016. The decrease was primarily due to lower commodity prices, increased DD&A mainly from Trains 1 and 2 being placed in service at APLNG, and a 2016 deferred tax charge of $174 million resulting from a tax functional currency change. The decrease in earnings was partly offset by higher sales volumes at APLNG and FCCL Partnership, as well as lower production taxes at Qatar Liquefied Gas Company Limited (3) (QG3).
Gain on dispositions decreased 39 percent in 2016. The decrease resulted from the absence of a $583 million before-tax gain in 2015 from the sales of producing properties in East Texas and North Louisiana, South Texas, and a certain pipeline and gathering assets in South Texas, as well as a $26 million before-tax loss on the sale of our interest in the Block B PSC in Indonesia in 2016. The decrease was partly offset by the absence of a $149 million before-tax loss on the disposition of non-core assets in western Canada in the fourth quarter of 2015; and gains on the 2016 dispositions of ConocoPhillips Senegal B.V., the entity that held our interests in three exploration blocks offshore Senegal, the Alaska Beluga River Unit natural gas field, and non-core assets in the Lower 48. For additional information on gains on dispositions, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
42
Other income increased 104 percent in 2016, mainly due to a gain of $88 million from our receipt of mineral properties and active leases from the Greater Northern Iron Ore Properties Trust in the fourth quarter of 2016. Other income was further increased $76 million before-tax for a damage claim settlement in our Lower 48 segment.
Purchased commodities decreased 20 percent in 2016, mainly due to lower natural gas prices.
Production and operating expenses decreased 19 percent in 2016, mainly due to lower operating expense activity, reduced headcount and dispositions of non-core assets, as well as favorable foreign currency impacts.
Selling, general and administrative (SG&A) expenses decreased 24 percent in 2016, primarily due to reduced restructuring expenses, lower headcount and reduced activity. The decrease was partly offset by increases from market impacts on certain compensation programs.
Exploration expenses decreased 54 percent in 2016, primarily as a result of lower leasehold impairment expense, dry hole costs, and other exploration expenses.
Leasehold impairment expense was reduced, mainly due to the absence of 2015 before-tax charges of $575 million for our Chukchi Sea leasehold and capitalized interest; $493 million for Angola Blocks 36 and 37; and $447 million for certain Gulf of Mexico leases, partly offset by 2016 impairments of our Melmar, Gibson, Tiber and other Gulf of Mexico leaseholds.
Dry hole costs were reduced due to the absence of before-tax charges of $1,141 million in 2015, mainly from wells in deepwater Gulf of Mexico, Horn River and Northwest Territories in Canada, Angola Blocks 36 and 37, and Malaysia. The reduction in costs was partly offset by before-tax charges in 2016, including $434 million from several wells in deepwater Gulf of Mexico and $256 million for two wells in Nova Scotia.
Other exploration expenses were reduced mainly due to the absence of a $335 million before-tax charge in 2015 related to the termination of our Ensco Gulf of Mexico deepwater drillship contract, partly offset by before-tax rig cancellation charges and third-party costs of $146 million for our final Gulf of Mexico deepwater drillship contract in 2016.
For additional information on leasehold impairments and other exploration expenses, see Note 8—Suspended Wells and Other Exploration Expenses, and Note 9—Impairments, in the Notes to Consolidated Financial Statements.
Impairments decreased 94 percent in 2016. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.
Taxes other than income taxes decreased 18 percent in 2016, primarily as a result of lower production taxes, mainly in our Alaska and Lower 48 segments, given reduced commodity prices and the absence of the impact of a transportation cost ruling by the Federal Energy Regulatory Commission in the fourth quarter of 2015 in Alaska. Taxes other than income taxes were additionally decreased due to lower property taxes in 2016 in our Alaska and Lower 48 segments.
Interest and debt expense increased 35 percent in 2016, primarily due to lower capitalized interest on projects and increased debt.
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax provision (benefit) and effective tax rate.
43
Sales and other operating revenues decreased 44 percent in 2015, mainly as a result of lower prices across all commodities. Lower prices were partly offset by higher crude oil and LNG sales volumes.
Equity in earnings of affiliates decreased 74 percent in 2015. The decrease was primarily due to lower earnings from FCCL and QG3, given lower commodity prices, partly offset by higher volumes and lower operational costs.
Gain on dispositionsincreased by $493 million in 2015. The increase resulted from a $583 million gain from the sales of producing properties in East Texas and North Louisiana, South Texas, and a certain pipeline and gathering assets in South Texas. Gains realized were partly offset by a net loss from the disposition of non-core assets in western Canada. For additional information on gains on dispositions, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
Other income decreased 66 percent in 2015, mainly due to the absence of 2014 income related to the resolution of a contingent liability in the Other International segment and a legal arbitration settlement in Asia Pacific and Middle East.
Purchased commodities decreased 44 percent in 2015, largely as a result of lower natural gas prices and the absence of a $130 million loss in the Lower 48 related to transportation and storage capacity agreements recognized in 2014.
Production and operating expenses decreased 21 percent in 2015, largely due to lower operating expense activity, including reduced turnarounds at our Bayu-Undan Field and Darwin LNG facility, favorable foreign exchange-related impacts, and the absence of an $849 million charge resulting from the Freeport LNG termination agreement in 2014. The decrease in expense was partially offset by restructuring expenses of $206 million in 2015.
SG&A expenses increased 30 percent in 2015, primarily due to $407 million in restructuring and pension settlement expenses, partially offset by lower staff and compensation plan costs.
Exploration expenses increased 105 percent in 2015, mainly as a result of higher unproved property impairments, primarily in Alaska, Angola and the Lower 48. Higher dry hole and other exploration costs, including a $253 million before-tax expense for wells charged to dry hole in Canada, a $383 million expense related to the termination of our Gulf of Mexico deepwater drillship contract, and a $176 million charge for two wells charged to dry hole in the Gila prospect in the deepwater Gulf of Mexico, also contributed to the increase in exploration expenses. For additional information on leasehold impairments and other exploration expenses, see Note 8—Suspended Wells and Other Exploration Expenses and Note 9—Impairments, in the Notes to Consolidated Financial Statements.
DD&A increased 9 percent in 2015. The increase was mainly associated with higher production volumes in the Lower 48 and Asia Pacific and Middle East and commodity price-related reserve revisions, partly offset by reserve additions in the Lower 48.
Impairments increased 162 percent in 2015. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.
Taxes other than income taxes decreased 57 percent in 2015, mainly due to lower production taxes from reduced commodity prices in the Lower 48, Alaska and Asia Pacific and Middle East.
Interest and debt expense increased 42 percent in 2015, primarily due to lower capitalized interest on projects and increased average debt levels in 2015.
44
Summary Operating Statistics
Average Net Production
Crude oil (MBD)*
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)**
Total Production (MBOED)***
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (per barrel)
Natural gas (per thousand cubic feet)
Worldwide Exploration Expenses
General and administrative; geological and geophysical, lease rental, and other
Leasehold impairment
Dry holes
Excludes discontinued operations.
Total production, including Libya, of 1,569 MBOED decreased 1 percent in 2016 compared with 2015. The decrease in total average production primarily resulted from normal field decline and the loss of 72 MBOED mainly attributable to the 2015 dispositions of several non-core assets in the Lower 48, western Canada and the sale of our interest in the Polar Lights Company in Russia. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Western North Slope in Alaska; the Kebabangan gas field in Malaysia; and the Greater Ekofisk Area in Norway. Improved drilling and well performance in Canada, Norway, the Lower 48, and China, as well as lower unplanned downtime in the Lower 48 also partly offset the decrease in production. Adjusted for downtime and dispositions of 66 MBOED, our production, excluding Libya, increased by 44 MBOED, or 3 percent, compared with 2015. Assets sold in 2016 produced 27 MBOED and 36 MBOED in 2016 and 2015, respectively.
In 2015, average production from continuing operations, including Libya, increased 3 percent compared with 2014, while average liquids production increased 4 percent. The increase in total average production in 2015 primarily resulted from additional production from major developments, including tight oil plays in the Lower 48; Gumusut in Malaysia; APLNG in Australia; Greater Britannia projects and the J-Area in the U.K.; and the ramp-up of Foster Creek Phase F in Canada. Improved well performance, mostly in the Lower 48, western Canada and Norway, and lower turnaround activity also contributed to higher production in 2015. These increases were largely offset by normal field decline. Adjusted for downtime and dispositions of 13 MBOED,
45
our production from continuing operations, excluding Libya, increased by 70 MBOED, or 5 percent, compared with 2014. Full-year 2015 production from assets sold or under agreement was 64 MBOED.
Income from Continuing Operations (millions of dollars)
Crude oil (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2016, Alaska contributed 19 percent of our worldwide liquids production and less than 1 percent of our natural gas production.
Alaska reported earnings of $319 million in 2016, compared with earnings of $4 million in 2015. The increase in earnings was mainly due to:
The increase in earnings was partly offset by lower crude oil prices and higher DD&A expense, mainly due to capital additions.
Average production increased 1 percent in 2016 compared with 2015, primarily due to new production from the Alpine CD5 drill site and strong well performance in the Greater Prudhoe Area. The production increase was partly offset by normal field decline.
Alaska reported earnings of $4 million in 2015, compared with earnings of $2,041 million in 2014, mainly due to lower commodity prices and a $368 million after-tax charge in the fourth quarter of 2015 for the impairment of our Chukchi Sea leasehold and capitalized interest. The earnings decrease was partly offset by reduced production taxes resulting from lower commodity prices.
46
Average production decreased 3 percent in 2015 compared with 2014, primarily due to normal field decline, partly offset by lower planned downtime activity and new production from the Western North Slope, Greater Prudhoe and Greater Kuparuk areas.
Loss from Continuing Operations (millions of dollars)
The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico. During 2016, the Lower 48 contributed 30 percent of our worldwide liquids production and 32 percent of our natural gas production.
Lower 48 reported a loss of $2,257 million after-tax in 2016, compared with a loss of $1,932 million after-tax in 2015. The increase in losses was primarily due to:
The increase in losses was partly offset by:
47
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. Our 2016 average realized crude oil price of $37.49 per barrel was 13 percent less than WTI of $43.20 per barrel. The differential is driven primarily by local market dynamics in the Gulf Coast, Bakken and the Permian Basin, and may remain relatively wide in the near term.
Total average production decreased 11 percent in 2016 compared with 2015. The decrease was mainly attributable to normal field decline and the 2015 disposition of non-core properties in East Texas and North Louisiana, as well as South Texas. The reduction was partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin, as well as lower unplanned downtime.
Lower 48 reported a loss of $1,932 million after-tax in 2015, compared with a loss of $22 million after-tax in 2014. The decrease in earnings was primarily due to:
These decreases were partly offset by the absence of a $545 million after-tax charge resulting from the Freeport LNG termination agreement in 2014; a $368 million after-tax gain on the disposition of certain properties in South Texas, East Texas and North Louisiana; higher volumes; lower production taxes; and the absence of a $151 million after-tax impairment charge resulting from reduced volume forecasts on proved properties and the associated undeveloped leasehold costs.
Total average production increased 2 percent in 2015 compared with 2014, while average crude oil production increased 10 percent across the same period. The increase was mainly attributable to new production, primarily from Eagle Ford, Bakken and the Permian Basin, partially offset by normal field decline.
48
Income (Loss) from Continuing Operations (millions of dollars)
Total bitumen
Bitumen (dollars per barrel)
Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2016, Canada contributed 23 percent of our worldwide liquids production and 14 percent of our worldwide natural gas production.
Canada operations reported a loss of $935 million in 2016, a decrease in loss of $109 million compared with 2015. The decrease in loss was primarily due to:
49
The decrease in loss was partly offset by lower commodity prices; higher DD&A expense, mainly from price-related reserve revisions; and a $42 million after-tax impairment charge related to certain developed properties in central Alberta, which were classified as held for sale, being written down to fair value less costs to sell.
Total average production decreased 3 percent in 2016 compared with 2015, while bitumen production increased 21 percent over the same periods. The decrease in total production was mainly attributable to the disposition of non-core assets in western Canada and normal field decline. The production decrease was partly offset by strong well performance in western Canada, Surmont and FCCL. Surmont has fully recovered from the forest fire impacts.
Canada operations reported a loss of $1,044 million in 2015, a reduction in earnings of $1,984 million compared with 2014. The decrease in earnings was primarily due to:
The earnings decrease was partly offset by higher bitumen production volumes; lower operating expenses and DD&A, both primarily from favorable foreign currency impacts; and the absence of the $109 million after-tax impairment of undeveloped leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties in 2014.
Total average production increased 8 percent in 2015 compared with 2014, while bitumen production increased 17 percent over the same periods. The increases in total production were mainly attributable to strong well performance in western Canada, lower royalty impacts, strong plant performance at Foster Creek and Christina Lake and the continued ramp-up of production from Foster Creek Phase F. These increases were partly offset by normal field decline and increased unplanned downtime, including the precautionary shut down of Foster Creek for nearby forest fires in the second quarter of 2015.
50
Crude oil (dollars per barrel)
The Europe and North Africa segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, the Norwegian Sea, and Libya. In 2016, our Europe and North Africa operations contributed 14 percent of our worldwide liquids production and 12 percent of our natural gas production.
Earnings for Europe and North Africa operations of $394 million decreased 4 percent in 2016. The decrease in earnings was primarily due to the absence of a $555 million net deferred tax benefit as a result of a change in the U.K. tax rate, effective at the beginning of 2015; lower crude oil and natural gas prices; lower sales volumes; and the absence of a 2015 after-tax gain of $49 million on the sale of our 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled).
The decrease in earnings was partly offset by:
Average production decreased 1 percent in 2016, compared with 2015. The decrease in production was mainly due to normal field decline, partly offset by improved drilling and well performance in Norway and new production from the Greater Ekofisk and Greater Britannia areas. Libya production remained largely shut in, as the Es Sider crude oil export terminal closure continued throughout the third quarter of 2016. Production resumed in Libya in October 2016, with three crude liftings from Es Sider in January 2017. We expect a gradual ramp-up in activity.
51
Earnings for Europe and North Africa operations decreased 50 percent in 2015. The decrease in earnings was primarily due to lower crude oil and natural gas prices. Earnings further decreased due to higher property impairments in the U.K., given lower natural gas prices and increases to asset retirement obligations. The earnings decrease was partly offset by a $555 million net deferred tax benefit as a result of a change in the U.K. tax rate, effective at the beginning of 2015, and an after-tax gain of $49 million on the sale of our 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled).
For additional information on the impairments, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.
Average production decreased 5 percent in 2015, compared with 2014. The decrease in production was mostly due to normal field decline and lower volumes from Libya, partly offset by the new production from the Greater Britannia Area, the J-Area and the Greater Ekofisk Area, as well as improved well performance in Norway.
The Es Sider Terminal in Libya remained shut in throughout 2015 as a result of civil unrest.
52
Total crude oil
Total natural gas liquids
Total natural gas
Natural gas liquids (dollars per barrel)
Natural gas (dollars per thousand cubic feet)
The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Brunei. During 2016, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 42 percent of our natural gas production.
Asia Pacific and Middle East reported earnings of $265 million in 2016, compared with a loss of $406 million in 2015. The earnings increase was mainly due to:
53
The earnings increase was partly offset by lower prices across all commodities; lower equity earnings from APLNG, mainly as a result of higher DD&A expense from APLNG Trains 1 and 2 coming online; and a third-quarter 2016 deferred tax charge of $174 million resulting from APLNG’s tax functional currency change.
Average production increased 15 percent in 2016, compared with 2015. The production increase in 2016 was mainly attributable to new production from the ramp-up of APLNG in Australia and the Kebabangan gas field in Malaysia, improved drilling and well performance in China and Malaysia, and increased recoveries from production sharing contracts in Indonesia. The production increase was partially offset by normal field decline across the segment.
Asia Pacific and Middle East reported a loss of $406 million in 2015, compared with income of $3,008 million in 2014. The decrease in earnings was mainly due to lower prices across all commodities. Earnings in 2015 were further decreased by a $1,502 million before- and after-tax charge for the impairment of our APLNG investment, higher DD&A expense from increased volumes, primarily in Malaysia, and a $41 million after-tax charge for the impairment of our relinquished Palangkaraya PSC. The earnings decrease was partially offset by lower production taxes, increased volumes, as well as lower feedstock costs and reduced turnarounds at our Bayu-Undan Field and Darwin LNG facility.
Average production increased 9 percent in 2015, compared with 2014. The production increase was mainly attributable to new production from Gumusut, in Malaysia, which came online in the fourth quarter of 2014; the ramp-up of APLNG production due to additional gas processing facilities online; and infill drilling in China. Production increases were partly offset by normal field decline.
The Other International segment includes exploration activities in Colombia and Chile.
54
Other International operations reported a loss of $16 million in 2016, compared with a loss of $593 million in 2015. The decrease in losses was primarily due to the absence of after-tax charges in 2015 of $235 million, $75 million and $32 million net for property impairments on our Angola Block 36, Angola Block 37 and Poland leasehold, respectively. Additionally, losses decreased due to the absence of the 2015 after-tax dry hole expenses offshore Angola of $81 million for the Omosi-1 well and $59 million for the Vali-1 well, combined with a $138 million gain on the disposition of ConocoPhillips Senegal B.V., the entity that held our interest in three exploration blocks offshore Senegal.
Other International operations reported a loss of $593 million in 2015, compared with a loss of $100 million in 2014. The decrease in earnings was primarily due to after-tax charges of $235 million, $75 million and $32 million net for property impairments on our Angola Block 36, Angola Block 37 and Poland leasehold, respectively. Earnings were also reduced due to increased dry hole expenses for the Omosi-1 and Vali-1 wells offshore Angola and the absence of other income of $154 million after-tax associated with the favorable resolution of a contingent liability. The reduction in earnings was partly offset by the absence of the $136 million after-tax charge in 2014 for the Kamoxi-1 exploration well, located offshore Angola; and a $53 million after-tax gain from the disposition of our interest in the Polar Lights Company.
Average production was flat in 2015 compared with 2014.
Income (Loss) from Continuing Operations
Net interest
Corporate general and administrative expenses
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 89 percent in 2016 compared with 2015, primarily as a result of the absence of the 2015 impacts from the fair market value of apportioning interest expense in the United States, lower capitalized interest on projects, and increased debt.
Corporate general and administrative expenses increased 17 percent in 2016, mainly due to increases from market impacts on certain compensation programs, partly offset by lower staff expenses.
Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on tight oil reservoirs, heavy oil and oil sands, as well as LNG. Earnings from Technology were $50 million in 2016, compared with $122 million in 2015. The decrease in earnings primarily resulted from lower licensing revenues, partly offset by reduced technology program spend.
55
The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. “Other” expenses decreased 34 percent in 2016, mainly due to lower restructuring costs and favorable foreign currency impacts, partly offset by the absence of a 2015 tax benefit.
Net interest increased 3 percent in 2015 compared with 2014, primarily as a result of lower capitalized interest on projects completed or sold and increased debt. The 2015 net interest expense increase was largely offset by a $148 million net tax benefit for electing the fair market value method of apportioning interest expense in the United States for prior years.
Corporate general and administrative expenses increased 27 percent in 2015, mainly due to $143 million in after-tax pension settlement expense, partially offset by lower staff and compensation plan costs.
Earnings from Technology were $122 million in 2015, compared with a loss of $93 million in 2014. The increase in earnings primarily resulted from higher licensing revenues.
Other expenses increased by $82 million in 2015, mainly due to $142 million after-tax in restructuring charges and foreign currency translation impacts, partially offset by lower environmental expenses.
56
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
Net cash provided by continuing operating activities
Net cash provided by discontinued operations
Cash and cash equivalents
Short-term debt
Total debt
Total equity
Percent of total debt to capital*
Percent of floating-rate debt to total debt
*Capital includes total debt and total equity.
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities. In addition, during 2016 we received $1,286 million in proceeds from asset sales and issued $4,594 million of new debt consisting of a three-year term loan and fixed rate notes. The primary uses of our available cash were $4,869 million to support our ongoing capital expenditures and investments program; $2,251 million to repay debt; $1,253 million to pay dividends on our common stock; and $126 million to repurchase common stock. During 2016, cash and cash equivalents increased by $1,242 million, to $3,610 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments and required debt payments.
Significant Sources of Capital
Operating Activities
During 2016, cash provided by operating activities was $4,403 million, a 42 percent decrease from 2015. The decrease was primarily due to lower prices across all commodities. Cash flows from operating activities were positively impacted by the $585 million and $642 million tax refunds received from the Internal Revenue Service during 2016 and 2015, respectively.
While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Our 2016 production averaged 1,569 MBOED. Full-year 2017 production is expected to be 1,540 to 1,570 MBOED, which results in flat to 2 percent growth compared with full-year 2016 production, excluding Libya, of 1,540 MBOED when adjusted for 2016 dispositions of 27 MBOED. Production guidance for 2017 excludes Libya and the impact of future dispositions. 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;
57
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 2016 was negative 194 percent. Over the five-year period ended December 31, 2016, our reserve replacement was 35 percent (including 11 percent from consolidated operations) reflecting the impact of lower prices and asset dispositions. 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 2017 capital budget, see the “2017 Capital Budget” section within “Capital Resources and Liquidity” and for additional information on 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 2016 and 2015, revisions decreased reserves, while in 2014, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.
Investing Activities
Proceeds from asset sales in 2016 were $1.3 billion, primarily from the sales of ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal; our 40 percent interest in South Natuna Sea Block B in Indonesia; our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet; and certain mineral and non-mineral fee lands in northeastern Minnesota. This compares with proceeds of $2.0 billion in 2015, primarily from the sales of certain western Canadian properties; producing properties in East Texas and North Louisiana and in South Texas; a certain pipeline and gathering assets in South Texas; and our 50 percent equity method investment in the Russian joint venture, Polar Lights Company. For additional information, see Note 6—Assets Held for Sale or Sold in the Notes to Consolidated Financial Statements, and the Outlook section within Management’s Discussion and Analysis.
Commercial Paper and Credit Facilities
On March 28, 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 billion to $6.75 billion. Our revolving credit facility may be used for direct bank borrowings, 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 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 $6.25 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $500 million commercial paper program, which is used to fund commitments relating to QG3. At both December 31, 2016 and 2015, we had no direct borrowings or letters of credit issued under the revolving credit facility. Under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, no commercial paper was outstanding at December 31, 2016, compared with $803 million at December 31, 2015. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at December 31, 2016.
58
Due to the significant decline in commodity prices during 2015, and the expectation these prices could remain depressed in the near future, the major ratings agencies conducted a review of the oil and gas industry. As a result of this review, our credit ratings, along with several other companies in the oil and gas industry, were downgraded. In the first quarter of 2016, Moody’s Investors Service downgraded our senior long-term debt ratings to “Baa2” from “A2,” with a negative outlook and our short-term commercial paper ratings to “Prime 2” from “Prime 1” and Fitch downgraded our long-term debt ratings to “A-” from “A” with a negative outlook and our short-term commercial paper ratings to “F2” from “F1.” In the second quarter of 2016, Standard and Poor’s downgraded our senior long-term debt ratings to “A-” from “A,” with a negative outlook and our short-term commercial paper ratings to “A-2” from “A-1.” 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 further downgrade of our credit rating. If our credit rating were downgraded further, it could increase the cost of corporate debt available to us and restrict our access to commercial paper. 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 revolving credit facility.
Certain of our project-related contracts, commercial 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, 2016 and December 31, 2015, we had direct bank letters of credit of $304 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of further credit ratings downgrades, we may be required to post additional letters of credit.
Shelf Registration
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.
For information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures” section.
Our debt balance at December 31, 2016, was $27.3 billion, an increase of $2.4 billion from the balance at December 31, 2015, primarily as a result of obtaining a $1.6 billion three-year term loan and the issuance of $3.0 billion in new fixed rate notes, both in March 2016, partly offset by the retirement in October 2016 of the $1,250 million of 5.625% Notes at maturity, the $803 million repayment of outstanding commercial paper, and early repayment of $150 million of our term loan. Our short-term debt balance at December 31, 2016, decreased $338 million compared with December 31, 2015, primarily as a result of the timing of scheduled maturities. For more information, see Note 11—Debt, in the Notes to Consolidated Financial Statements.
To preserve our balance sheet strength and provide financial flexibility through the recent downturn, in the first quarter of 2016, we announced a reduction in the quarterly dividend to $0.25 per share. The dividend was paid March 1, 2016, to stockholders of record at the close of business on February 16, 2016. In July 2016, we announced a dividend of $0.25 per share. The dividend was paid September 1, 2016, to stockholders of record at the close of business on July 25, 2016. In October 2016, we announced a dividend of $0.25 per share. The dividend was paid December 1, 2016, to stockholders of record at the close of business on October 17, 2016.
59
Additionally, on January 31, 2017, we announced an increase to our quarterly dividend of 6 percent, from $0.25 per share to $0.265 per share. The dividend will be paid March 1, 2017, to stockholders of record at the close of business on February 14, 2017.
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock over the next three years. Repurchase of shares began in November and totaled 2,579,098 shares at a cost of $126 million, through December 31, 2016.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2016:
2–3
4–5
Debt obligations (a)
Capital lease obligations (b)
Interest on debt and other obligations
Operating lease obligations (c)
Purchase obligations (d)
Other long-term liabilities
Pension and postretirement benefit contributions (e)
Asset retirement obligations (f)
Accrued environmental costs (g)
Unrecognized tax benefits (h)
Total
The majority of the purchase obligations are market-based contracts related to our commodity business. Product purchase commitments with third parties totaled $4,673 million.
Purchase obligations of $6,232 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.
60
Capital Expenditures
Capital expenditures and investments from continuing operations
Discontinued operations in Nigeria
Capital Program
Our capital expenditures and investments from continuing operations for the three-year period ended December 31, 2016, totaled $32 billion. The 2016 expenditures supported key exploration and developments, primarily:
61
2017 CAPITAL BUDGET
In 2016, given our view of greater price volatility, we announced a plan for allocating cash across the business which sets annual capital at a level that maintains flat production volumes. Our 2017 capital budget of $5 billion reaffirms this strategy. We have shifted our capital allocation to focus on value-preserving, shorter cycle time and low cost-of-supply unconventional programs in our resource base.
We are planning to allocate approximately:
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 filed 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. For information on other contingencies, see “Critical Accounting Estimates” and Note 13—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 and tax 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 19—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income tax-related contingencies.
62
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:
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.
63
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, 2016, there were 14 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.
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 $435 million in 2016 and are expected to be about $470 million per year in 2017 and 2018. Capitalized environmental costs were $192 million in 2016 and are expected to be about $275 million per year in 2017 and 2018.
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.
64
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, 2016, our balance sheet included total accrued environmental costs of $247 million, compared with $258 million at December 31, 2015, 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:
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.
65
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:
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:
The company uses an estimated market cost of GHG emissions in the range of $9 to $43 per tonne depending on the timing and country or region to evaluate future opportunities.
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.
66
NEW ACCOUNTING STANDARDS
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB Accounting Standards Codification (ASC) Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. While we continue to evaluate the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures. For additional information, see Note 25—New Accounting Standards, in the Notes to Consolidated Financial Statements.
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 2016, 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 $404 million and the accumulated impairment reserve was $197 million.
67
The weighted-average judgmental percentage probability of ultimate failure was approximately 69 percent, and the weighted-average amortization period was approximately two years. If that judgmental percentage were to be raised by 5 percent across all calculations, before-tax leasehold impairment expense in 2017 would increase by approximately $5 million. At year-end 2016, the remaining $3,659 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. Of this amount, approximately $2.5 billion is concentrated in nine major development areas, the majority of which are not expected to move to proved properties in 2017. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.
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 development.
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 2016, total suspended well costs were $1,063 million, compared with $1,260 million at year-end 2015. For additional information on suspended wells, including an aging analysis, see Note 8—Suspended Wells and Other Exploration Expenses, 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.”
68
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 theunit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2016, the net book value of productive properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $60 billion and the DD&A recorded on these assets in 2016 was approximately $8.6 billion. The estimated proved developed reserves for our consolidated operations were 4.0 billion BOE at the end of 2015 and 3.7 billion BOE at the end of 2016. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2016 would have increased by an estimated $955 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 before-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. Differing assumptions could affect the timing and the amount of an impairment in any period. See Note 9—Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value.
69
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. See the “APLNG” section of Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information.
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. See Note 10—Asset Retirement Obligations and Accrued Environmental Costs, in the Notes to Consolidated Financial Statements, for additional information.
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 plans. 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
70
purposes differ in certain important respects. Ultimately, we will be required to fund all vested 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 $1,100 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 $90 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $50 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. In the event there is a significant reduction in the expected years of future service of present employees or elimination for a significant number of employees the accrual of defined benefits for some or all of their future services, we could recognize a curtailment gain or loss. See Note 18—Employee Benefit Plans, in the Notes to Consolidated Financial Statements, for additional information.
A number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages, and underpayments associated with environmental remediation, tax, contracts, and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure. However, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration, or other third party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity.”
71
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. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often 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, but not limited to, the following:
72
73
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 Executive Vice President of Finance, Commercial, and Chief Financial Officer, who reports to the Chief Executive Officer, monitors commodity price risk and risks resulting from foreign currency exchange rates and interest rates. 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:
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, 2016, 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 or held for purposes other than trading at December 31, 2016 and 2015, was 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.
74
Expected Maturity Date
RateMaturity
Year-End 2016
2017
2018
2019
2020
2021
Remaining years
Fair value
Year-End 2015
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, 2016 and 2015, 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, 2016, or 2015, exchange rates. The notional and fair market values of these positions at December 31, 2016 and 2015, were as follows:
75
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
Sell U.S. dollar, buy Canadian dollar
Sell U.S. dollar, buy Norwegian krone
Buy U.S. dollar, sell Canadian dollar
Buy U.S. dollar, sell British pound
Buy British pound, sell Canadian dollar
Buy British pound, sell Euro
Sell British pound, buy Norwegian krone
*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 14—Derivative and Financial Instruments, in the Notes to Consolidated Financial Statements.
76
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
Report of Management
Reports of Independent Registered Public Accounting Firm
Consolidated Income Statement for the years ended December 31, 2016, 2015 and 2014
Consolidated Statement of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheet at December 31, 2016 and 2015
Consolidated Statement of Cash Flows for the years ended December 31, 2016, 2015 and 2014
Consolidated Statement of Changes in Equity for the years ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
Supplementary Information
Oil and Gas Operations
Selected Quarterly Financial Data
Condensed Consolidating Financial Information
77
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, 2016. 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, 2016.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2016, and their report is included herein.
Chairman and
Chief Executive Officer
Executive Vice President, Finance,
Commercial and Chief Financial Officer
February 21, 2017
78
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 21, 2017, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
79
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2016, 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 that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or 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, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2016 consolidated financial statements of ConocoPhillips and our report dated February 21, 2017, expressed an unqualified opinion thereon.
80
Years Ended December 31
Revenues and Other Income
Equity in earnings of affiliates
Gain on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction gains
Total Costs and Expenses
Income (loss) from continuing operations before income taxes
Income tax provision (benefit)
Income (Loss) From Continuing Operations
Income from discontinued operations*
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Amounts Attributable to ConocoPhillips Common Shareholders:
Net Income (Loss)
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Continuing operations
Discontinued operations
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock
Dividends Paid Per Share of Common Stock (dollars)
Average Common Shares Outstanding (in thousands)
*Net of provision for income taxes on discontinued operations of:
See Notes to Consolidated Financial Statements.
81
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
Reclassification adjustment for amortization of prior service credit included in net income
Net change
Net actuarial gain (loss) arising during the period
Reclassification adjustment for amortization of net actuarial losses included in net income
Nonsponsored plans*
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Foreign currency translation adjustments
Reclassification adjustment for gain included in net income
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income (Loss) Attributable to ConocoPhillips
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
82
Assets
Short-term investments
Accounts and notes receivable (net of allowance of $5 million in 2016 and $7 million in 2015)
Accounts and notes receivable—related parties
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment (net of accumulated depreciation, depletionand amortization of $73,075 million in 2016 and $70,413 million in 2015)
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2016—1,782,079,107 shares; 2015—1,778,226,388 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2016—544,809,771 shares; 2015—542,230,673 shares)
Accumulated other comprehensive loss
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
83
Cash Flows From Operating Activities
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Dry hole costs and leasehold impairments
Deferred taxes
Undistributed equity earnings
Working capital adjustments
Decrease in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Decrease in accounts payable
Decrease in taxes and other accruals
Net Cash Provided by Operating Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net sales (purchases) of short-term investments
Collection of advances/loans—related parties
Net cash used in continuing investing activities
Net cash used in discontinued operations
Net Cash Used in Investing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Net Cash Provided by (Used in) Financing Activities
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
84
December 31, 2013
Net income
Other comprehensive loss
Distributions to noncontrolling interests and other
Distributed under benefit plans
December 31, 2014
December 31, 2015
Other comprehensive income
December 31, 2016
85
Note 1—Accounting Policies
We manage our operations through six operating segments, defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International. For additional information, see Note 24—Segment Disclosures and Related Information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.
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).
86
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.
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.
87
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 dry holes when it judges the potential field does not warrant further investment in the near term. See Note 8—Suspended Wells and Other Exploration Expenses, for additional information on suspended wells.
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.
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.
88
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, which we record on a discounted basis) 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.
89
Note 2—Change in Accounting Principles
We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-02, “Amendments to the Consolidation Analysis,” beginning January 1, 2016. The ASU amends existing requirements applicable to reporting entities that are required to evaluate whether certain legal entities, including variable interest entities (VIEs), should be consolidated. The adoption of this ASU did not have an impact on our consolidated financial statements and disclosures. See Note 4 —Variable Interest Entities, for additional information on our significant VIEs.
Note 3—Discontinued Operations
On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business, which was previously part of the Other International operating segment. On July 30, 2014, we completed the sale 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. We recognized a before-tax gain of $1,052 million, which is included in the “Income from discontinued operations” line on our consolidated income statement.
Sales and other operating revenues and income from discontinued operations related to the Nigeria business during 2014 were as follows:
Sales and other operating revenues from discontinued operations
Income from discontinued operations before-tax
Income tax expense
90
Note 4—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:
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, 2016, 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 7—Investments, Loans and Long-Term Receivables, and Note 12—Guarantees, for additional information.
Marine Well Containment Company, LLC (MWCC)
MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on a call-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on the ten member Executive Committee responsible for overseeing the affairs of MWCC. During the year ended December 31, 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our consolidated balance sheet. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.
At December 31, 2016, the book value of our equity method investment in MWCC was $148 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.
Note 5—Inventories
Inventories at December 31 were:
Crude oil and natural gas
Materials and supplies
Inventories valued on the LIFO basis totaled $269 million and $317 million at December 31, 2016 and 2015, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $104 million and $6 million at December 31, 2016 and December 31, 2015, respectively. In 2016, liquidation of LIFO inventory values increased the net loss from continuing operations by $9 million.
91
Note 6—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 our consolidated income statement.
On April 22, 2016, we sold our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet for $134 million, net of settlement of gas imbalances and customary adjustments, and recognized a gain on disposition of $56 million. At the time of disposition, the net carrying value of our Beluga River Unit interest, which was included in the Alaska segment, was $78 million, consisting primarily of $100 million of PP&E and $19 million of asset retirement obligations (ARO).
On October 13, 2016, we completed an asset exchange with Bonavista Energy in which we gave up approximately 141,000 net acres of non-core developed properties in central Alberta in exchange for approximately 40,000 net acres of primarily undeveloped properties in northeast British Columbia. The fair value of the transaction was determined to be approximately $69 million and a before-tax impairment of $57 million was recognized in the third quarter of 2016 when the assets were considered held for sale, to reduce the carrying value to fair value. In the fourth quarter, a loss on disposition of approximately $1 million was recognized upon completion of the transaction. The divested properties were included in the Canada segment.
On October 28, 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal for $442 million and recognized a gain on disposition of $146 million. At the time of disposition, the carrying value of our interest was $286 million, which was primarily PP&E. Senegal results of operations were reported within our Other International segment.
On November 17, 2016, we completed the sale of our 40 percent interest in South Natuna Sea Block B for $225 million and recognized a loss on disposition of $26 million. Our interest in Block B was included in the Asia Pacific and Middle East segment. Previously, in the third quarter of 2016, we recognized a before-tax impairment of $42 million at the time it was considered held for sale to reduce the carrying value to fair value. At the time of the disposition, the carrying value of our interest was approximately $251 million, which included primarily $154 million of PP&E, $178 million of accounts receivable, $25 million of inventory, $54 million of deferred tax assets, $130 million of accounts payable and other accruals, and $38 million of employee benefit obligations.
On December 8, 2016, we completed the sale of certain mineral and non-mineral fee lands in northeastern Minnesota, which was included in the Lower 48 segment, for $148 million and recorded a gain on disposition of $4 million. The majority of the assets sold were acquired during the fourth quarter of 2016 as a result of ConocoPhillips holding a reversionary interest in the Greater Northern Iron Ore Properties Trust (the Trust), a grantor trust that owned mineral and surface interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminated on April 6, 2015 and in November 2016, upon completion of the wind-down period, documents memorializing ConocoPhillips’ ownership of certain Trust property, including all of the Trust’s mineral properties and active leases, were delivered to us and we recognized the fair value of the net assets resulting in a gain of $88 million recorded in the “Other income” line on our consolidated income statement. At the time of the disposition, the carrying value of our interests, which included the assets obtained from the Trust, consisted of $144 million of PP&E.
92
In November 2015, we sold a portion of our western Canadian properties located in British Columbia, Alberta, and Saskatchewan for $198 million and recognized a gain on disposition of $66 million. At the time of the disposition, the carrying value of our interest, which was included in the Canada segment, was $132 million, which included primarily $379 million of PP&E and $248 million of ARO.
In December 2015, we sold a portion of our western Canadian properties located in central Alberta for $130 million and recognized a loss on disposition of $235 million. At the time of the disposition, the carrying value of our interest, which was included in the Canada segment, was approximately $365 million, which included primarily $488 million of PP&E and $126 million of ARO.
Additionally, other December 2015 disposition transactions are summarized below.
We sold producing properties in East Texas and North Louisiana for $412 million and recognized a gain on disposition of $189 million. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $223 million, which included $351 million of PP&E and $128 million of ARO.
We sold certain gas producing properties in South Texas for $358 million and recognized a gain on disposition of $201 million. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $157 million, which included $369 million of PP&E and $212 million of ARO.
We sold certain pipeline and gathering assets in South Texas for $201 million and recognized a gain on disposition of $193 million. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $8 million, which primarily included $24 million of PP&E and $18 million of ARO.
We also sold our 50 percent interest in the Russian joint venture, Polar Lights Company, for $98 million and recognized a gain on disposition of $58 million. At the time of the disposition, the carrying value of our equity method investment in Polar Lights Company, which was included in our Other International segment, was approximately $40 million.
2014
For information on the sale of our Nigeria business, which is included in the “Income from discontinued operations” line on our consolidated income statement, see Note 3—Discontinued Operations.
Note 7—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity investments
Long-term receivables
Other investments
93
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2016, included:
Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows:
Revenues
Income before income taxes
Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
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, 2016, retained earnings included $1,392 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $398 million, $876 million and $2,648 million in 2016, 2015 and 2014, 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. The majority of APLNG LNG is sold under two long-term sales and purchase agreements, supplemented with sales of additional LNG spot cargoes targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we operate the LNG facility.
APLNG executed project financing agreements for an $8.5 billion project finance facility in 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, 2016, $8.5 billion had been drawn from the facility.
94
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. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. See Note 12—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 4—Variable Interest Entities (VIEs) for additional information.
On July 1, 2016, APLNG changed its tax functional currency from Australian dollar to U.S. dollar and translated all APLNG assets and liabilities into U.S. dollar, utilizing the exchange rate as of that date. As a result of this change, we recorded a reduction to our investment in APLNG for the deferred tax effect of $174 million in the “Equity in earnings (losses) of affiliates” line of our consolidated income statement.
During the fourth quarter of 2015, due to the outlook for crude oil and natural gas prices at that time, the estimated fair value of our investment in APLNG declined to an amount below book value. Accordingly, we recorded a noncash $1,502 million before- and after-tax impairment, in our fourth-quarter 2015 results.
During the third quarter of 2016, the outlook for crude oil prices weakened again, and as a result, the estimated fair value of our investment in APLNG declined to an amount below book value as of September 30, 2016. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment was not other than temporary under the guidance of FASB Accounting Standards Codification (ASC) Topic 323, “Investments – Equity Method and Joint Ventures.”
During the fourth quarter of 2016, primarily due to the impact of accretion on discounted cash flows from the passage of time and strengthening of the U.S. dollar, the estimated fair value of our investment increased and is above book value as of December 31, 2016. The expected future cash flows used for the impairment review of our investment in APLNG are based on estimated future production, an outlook of future prices from a combination of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign exchange rates provided by a third party, and a discount rate believed to be consistent with those used by principal market participants. Unfavorable changes in any of these assumptions could result in a reduction in future cash flows and could indicate impairment in the future. Subsequent to December 31, 2016, the outlook for crude prices and the U.S. dollar exchange rate relative to the Australian dollar has weakened. If these outlooks remain unchanged, we expect the estimated fair value of our investment in APLNG to be below book value at March 31, 2017.
At December 31, 2016, the book value of our equity method investment in APLNG was $10,089 million. 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 $8,348 million, resulting in a basis difference of $1,741 million on our books. The basis difference, which is substantially all associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to individual exploration and production license areas owned by APLNG, some 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 (loss) attributable to ConocoPhillips for 2016, 2015 and 2014 was after-tax expense of $92 million, $21 million and $24 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.
95
At December 31, 2016, the book value of our investment in FCCL was $8,784 million, net of a $1,706 million reduction due to cumulative foreign currency translation effects. 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. 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 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 $696 million as described below under “Loans and Long-Term Receivables.” At December 31, 2016, the book value of our equity method investment in QG3, excluding the project financing, was $869 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.
Through November 2014, we had an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas. We had no ownership in Freeport LNG; however, we had a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We had 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 would have expired 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 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 the cash flows from operating activities section on our consolidated statement of cash flows, while the receipt of the funds from Freeport LNG to repay the outstanding loan is included in the cash flows from investing activities section in 2014. 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 2014, and our terminal regasification capacity was reduced to zero.
96
At December 31, 2016, significant loans to affiliated companies include $696 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 commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Semi-annual repayments began in January 2011 and will extend through July 2022.
The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
Note 8—Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2016, 2015 and 2014:
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties
Sales of suspended well investment
Charged to dry hole expense
Ending balance at December 31
The following table provides an aging of suspended well balances at December 31:
Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year
Ending balance
Number of projects with exploratory well costs capitalized for a period greater than one year
97
The following table provides a further aging of those exploratory well costs that have been capitalized for more
than one year since the completion of drilling as of December 31, 2016:
Greater Poseidon—Australia(2)
Shenandoah—Lower 48(1)
Greater Clair—UK(2)
Surmont 3 and beyond—Canada(1)
NPRA—Alaska(1)
Caldita/Barossa—Australia(1)
Middle Magdalena Basin—Colombia(1)
Limbayong—Malaysia(1)
Alpine Satellite—Alaska(2)
Bohai—China(2)
Kamunsu East—Malaysia(2)
NC 98—Libya(2)
Sunrise—Australia(2)
Other of $10 million or less each(1)(2)
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
In line with our July 2015 announcement of plans to reduce future deepwater exploration spending, we recognized before-tax cancellation costs of $335 million and wrote off $48 million of before-tax capitalized rig costs in relation to the termination of our Gulf of Mexico deepwater drillship contract with Ensco in the Lower 48 segment in the third quarter of 2015. In July 2016, we entered into an agreement to terminate our final Gulf of Mexico deepwater drillship contract. The drillship, used to drill our operated deepwater well inventory in the Gulf of Mexico through April 2016, was contracted on a shared, three-year term. Accordingly, we recorded before-tax rig cancellation charges and third party costs of $146 million in our Lower 48 segment in 2016. These charges are included in the “Exploration expenses” line on our consolidated income statement.
In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we will recognize a before-tax charge of $43 million net in the first quarter of 2017.
98
Note 9—Impairments
During 2016, 2015 and 2014, we recognized the following before-tax impairment charges:
Corporate
In Lower 48, we recorded impairments of $149 million primarily due to cancelled projects associated with plan of development changes for Eagle Ford infrastructure, as well as lower natural gas prices and increased asset retirement obligation estimates.
In Canada, we recorded impairments of $88 million mainly due to plan of development changes, as well as certain developed properties, which were classified as held for sale, being written down to fair value less costs to sell.
In Europe, we recorded a credit to impairment of $160 million, primarily in the United Kingdom, due to decreased asset retirement obligation estimates on fields that are nearing the end of life and were impaired in prior years, partly offset by asset impairments due to lower natural gas prices in the United Kingdom.
In Asia Pacific and Middle East, we recorded impairments of $44 million, mainly due to the write-down to fair value less costs to sell of our developed properties in Block B, offshore Indonesia, in the third quarter of 2016.
In Corporate, we recorded impairments of $17 million due to cancelled projects in our Houston and Bartlesville offices.
The charges discussed below, within this section, are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.
Charges recorded in exploration expenses in 2016 were related to our decision announced in 2015 to reduce deepwater exploration spending.
In our Lower 48 segment, we recorded a $203 million before-tax impairment for the associated carrying value of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico. Additionally, we recorded a $95 million before-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect and a $79 million impairment, primarily as a result of changes in the estimated market value following the completion of marketing efforts.
In our Canada segment, we recorded before-tax unproved property impairments of $31 million, primarily due to decisions to discontinue further testing of undeveloped leaseholds.
See the “APLNG” section of Note 7—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment included within the Asia Pacific and Middle East segment.
99
In Europe, we recorded impairments of $724 million, primarily in the United Kingdom as a result of lower natural gas prices and increases to asset retirement obligations.
In our Other International segment, we decided not to pursue further evaluation of our Block 36 and Block 37 leases in Angola due to lack of commerciality of wells. Accordingly, we recorded impairments of $377 million and $116 million, respectively, for the associated carrying values of capitalized undeveloped leasehold costs.
In our Lower 48 segment, we decided not to conduct further activity on certain Gulf of Mexico leases, given our strategic plans to reduce deepwater exploration spending, and accordingly recorded impairments of $399 million for the associated carrying value of certain capitalized undeveloped leasehold costs.
In our Asia Pacific and Middle East segment, we decided to relinquish our Palangkaraya PSC in Indonesia. Accordingly, we recorded an impairment of $105 million for the associated carrying values of capitalized undeveloped leasehold cost.
In our Alaska segment, we recorded an impairment of $575 million for the associated carrying value of capitalized undeveloped leasehold cost in the Chukchi Sea in Alaska.
In our Canada segment, we recorded an impairment of $102 million for the Duvernay, Thornbury, Saleski and Crow Lake areas driven primarily by the lack of commerciality of wells.
In Alaska, we recorded impairments of $59 million, primarily due to a cancelled project.
In our Lower 48 segment, we recorded impairments of $208 million, primarily as a result of reduced volume forecasts for an onshore field, as well as an LNG-related pipeline.
We recorded impairments of $38 million in our Canada segment, primarily due to reduced volume forecasts and lower natural gas prices.
In Europe, we recorded impairments of $541 million, mainly due to reduced volume forecasts, increases in the ARO and lower natural gas prices for properties in the United Kingdom which are nearing the end of their useful lives.
In our Lower 48 segment, we recorded unproved property impairments of $239 million, primarily due to decisions to discontinue further testing of the undeveloped leaseholds.
Additionally, we decided not to pursue future development of the Amauligak discovery. Accordingly, we recorded a $145 million property impairment for the carrying value of capitalized undeveloped leasehold costs associated with our Amauligak, Arctic Islands and other Beaufort properties located offshore Canada.
100
Note 10—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Asset retirement obligations
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one year*
Long-term asset retirement obligations and accrued environmental costs
*Classified as a current liability on the balance sheet under “Other accruals.”
Asset Retirement Obligations
We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement 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 increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
We have numerous asset retirement obligations we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska.
During 2016 and 2015, our overall asset retirement obligation changed as follows:
Balance at January 1
Accretion of discount
New obligations
Changes in estimates of existing obligations
Spending on existing obligations
Property dispositions
Foreign currency translation
Balance at December 31
101
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2016 and 2015, were $247 million and $258 million, respectively.
We had accrued environmental costs of $183 million and $184 million at December 31, 2016 and 2015, respectively, related to remediation activities in the United States and Canada. We had also accrued in Corporate and Other $51 million and $57 million of environmental costs associated with sites no longer in operation at December 31, 2016 and 2015, respectively. In addition, $13 million and $17 million were included at both December 31, 2016 and 2015, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.
Expected expenditures for environmental obligations acquired in various business combinations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $92 million at December 31, 2016. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $9 million in 2017, $12 million in 2018, $8 million in 2019, $5 million in 2020, $4 million in 2021, and $110 million for all future years after 2021.
102
Note 11—Debt
Long-term debt at December 31 was:
9.125% Debentures due 2021
8.20% Debentures due 2025
8.125% Notes due 2030
7.9% Debentures due 2047
7.8% Debentures due 2027
7.65% Debentures due 2023
7.40% Notes due 2031
7.375% Debentures due 2029
7.25% Notes due 2031
7.20% Notes due 2031
7% Debentures due 2029
6.95% Notes due 2029
6.875% Debentures due 2026
6.65% Debentures due 2018
6.50% Notes due 2039
6.00% Notes due 2020
5.951% Notes due 2037
5.95% Notes due 2036
5.95% Notes due 2046
5.90% Notes due 2032
5.90% Notes due 2038
5.75% Notes due 2019
5.625% Notes due 2016
5.20% Notes due 2018
4.95% Notes due 2026
4.30% Notes due 2044
4.20% Notes due 2021
4.15% Notes due 2034
3.35% Notes due 2024
3.35% Notes due 2025
2.875% Notes due 2021
2.4% Notes due 2022
2.2% Notes due 2020
1.5% Notes due 2018
1.05% Notes due 2017
Floating rate term loan due 2019 at 1.94% – 2.31% during 2016
Floating rate notes due 2018 at 0.69% – 1.24% during 2016 and 0.61% – 0.69% during 2015
Floating rate notes due 2022 at 1.26% – 1.81% during 2016 and 1.18% – 1.26% during 2015
Commercial paper at 0.16% – 0.80% during 2015
Industrial Development Bonds due 2016 through 2038 at 0.01% – 0.91% during 2016 and 0.01% – 0.13% during 2015
Marine Terminal Revenue Refunding Bonds due 2031 at 0.01% – 0.95% during 2016 and 0.01% – 0.14% during 2015
Debt at face value
Capitalized leases
Net unamortized premiums, discounts and debt issuance costs
103
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2017 through 2021 are: $1,089 million, $1,894 million, $3,784 million, $1,593 million and $2,235 million, respectively.
In the first quarter of 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 billion to $6.75 billion. 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.
We have two commercial paper programs supported by our $6.75 billion revolving credit facility: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.
At both December 31, 2016 and 2015, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of December 31, 2016 and 2015. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, no commercial paper was outstanding at December 31, 2016, compared with $803 million at December 31, 2015. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at December 31, 2016.
In March 2016, we issued notes consisting of:
In addition, on March 18, 2016, we entered into a $1,600 million three-year senior unsecured term loan facility. In December 2016, an early repayment of $150 million reduced the loan to $1,450 million. We have the right at any time and from time to time to prepay the term loan, in whole or in part, without premium or penalty upon notice to the Administrative Agent. Borrowings will accrue interest at a base rate or, for certain Eurodollar borrowings, the London Interbank Offered Rate (LIBOR), in each case plus a margin that is set based on our corporate credit ratings. The applicable margin for loans bearing interest based on the base rate ranges from 0.50% to 1.00% and the applicable margin for loans bearing interest based on LIBOR ranges from 1.50% to 2.00%. Based on our current corporate credit ratings, the applicable margin for loans accruing interest at the base rate is 0.50% and the applicable margin for loans accruing interest at LIBOR is 1.50%.
The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At December 31, 2016, we were in compliance with this covenant.
104
The term loan facility includes customary events of default (subject to specified cure periods, materiality qualifiers and exceptions), including the failure to pay any interest, principal or fees when due, the failure to perform or the violation of any covenant contained in the term loan facility, the making of materially inaccurate or false representations or warranties, a default on certain material indebtedness, insolvency or bankruptcy, a change of control and the occurrence of material Employee Retirement Income Security Act of 1974 (ERISA) events and certain judgments against us or our material subsidiaries.
The net proceeds of the notes and term loan will be used for general corporate purposes.
On October 17, 2016, the $1,250 million 5.625% Notes due 2016 were repaid at maturity.
At both December 31, 2016 and 2015, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. The VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.
During 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. The FPS lease provides for an initial noncancelable term of 15 years, a subsequent 5-year cancelable term with no required lease payments, and an additional 5-year term with terms and conditions to be agreed at a later date. The lease has no ongoing purchase options or escalation clauses. Adjustments to provisional contingent rental payments may occur due to the finalization of actual commissioning costs. The lease does not impose any significant restrictions concerning dividends, debt or further leasing activities.
A capital lease asset and capital lease obligation were recognized for our proportionate interest in the FPS of $906 million, based on the present value of the future minimum lease payments using our before-tax incremental borrowing rate of 3.58 percent for debt with similar terms. Unitization of the Gumusut development with Brunei was recorded during the fourth quarter of 2015 and reduced our proportionate interest in the FPS from 33 percent to 29 percent. The net carrying value of the capital lease asset was approximately $540 million and $707 million as of December 31, 2016 and December 31, 2015, respectively. The capital lease asset is being depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement. As of December 31, 2016 and December 31, 2015, accumulated depreciation of the capital lease asset amounted to approximately $268 million and $122 million, respectively.
At December 31, 2016, future minimum payments due under capital leases were:
Less: portion representing imputed interest
Capital lease obligations
105
Note 12—Guarantees
At December 31, 2016, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
APLNG Guarantees
At December 31, 2016, we had outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing December 2016 exchange rates:
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $540 million, which consist primarily of a guarantee of the residual value of a leased office building, guarantees of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts.
106
These guarantees have remaining terms of up to six years and would become payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties.
Indemnifications
Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at December 31, 2016, was approximately $100 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount at December 31, 2016, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.
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. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.
On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our downstream business formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.4 billion. At December 31, 2016, the carrying value of this guarantee is approximately $98 million and the remaining term is eight years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.
Note 13—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed 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. See Note 19—Income Taxes, for additional information about income tax-related contingencies.
107
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.
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 10—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
108
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2016, we had performance obligations secured by letters of credit of $304 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.
In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. Separate arbitrations for contractual compensation against PDVSA are also pending before an International Chamber of Commerce (ICC) arbitration tribunal. In addition, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims is complete. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and its co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set.
In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the Block 36 Production Sharing Contract relating to disputes arising thereunder. The arbitration will be conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three person tribunal.
109
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2017—$24 million; 2018—$20 million; 2019—$7 million; 2020—$7 million; 2021—$7 million; and 2022 and after—$75 million. Total payments under the agreements were $42 million in 2016, $27 million in 2015 and $127 million in 2014.
Note 14—Derivative and Financial Instruments
We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.
Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.
The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:
110
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
Basis
We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.
The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:
The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our consolidated income statement were:
Foreign currency transaction (gains) losses
We had the following net notional position of outstanding foreign currency exchange derivatives:
In Millions
Notional Currency
Sell U.S. dollar, buy other currencies*
Buy U.S. dollar, sell other currencies**
Buy British pound, sell other currencies***
*Primarily Canadian dollar, Norwegian krone and British pound.
**Primarily Canadian dollar and British pound.
***Primarily Canadian dollar and Euro.
111
Financial Instruments
We have certain financial instruments on our consolidated balance sheet related to interest-bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.
Cash
Time deposits
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.
The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position on December 31, 2016 and December 31, 2015, was $42 million and $158 million, respectively. For these instruments, no collateral was posted as of December 31, 2016, and $2 million of collateral was posted as of December 31, 2015.
112
If our credit rating had been downgraded below investment grade on December 31, 2016, we would be required to post $42 million of additional collateral, either with cash or letters of credit.
Note 15—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1 during 2016 or 2015.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.
The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):
Commodity derivatives
Total liabilities
113
The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of offset exists.
At December 31, 2016 and December 31, 2015, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.
Non-Recurring Fair Value Measurement
The following table summarizes the fair value hierarchy by major category for assets accounted for at fair value on a non-recurring basis:
Year ended December 31, 2016
Net PP&E (held for use)
March 31, 2016
June 30, 2016
Net PP&E (held for sale)
September 30, 2016
Cost and equity method investments
Year ended December 31, 2015
March 31, 2015
June 30, 2015
September 30, 2015
Net PP&E (unproved property)
Equity method investments
114
Net PP&E held for use is comprised of various producing properties impaired to their individual fair values less costs to sell. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount rate believed to be consistent with those used by principal market participants.
Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its negotiated selling price.
Net PP&E unproved property is comprised of unproved leaseholds impaired to our best estimate of sales value less costs to sell.
Equity Method Investments
Certain cost and equity method investments were determined to have fair values below their carrying amounts, and the impairments were considered to be other than temporary under the guidance of FASB ASC Topic 323. An investment using Level 1 inputs was written down to fair value, less costs to sell, determined by its negotiated selling price. Investments using Level 3 inputs had fair values determined primarily by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount factor believed to be consistent with those used by principal market participants. During 2015, this primarily included our investment in APLNG, which was written down to its fair value of $10,185 million, resulting in a charge of $1,502 million before-tax. For additional information on APLNG, see Note 7—Investments, Loans and Long-Term Receivables.
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
115
The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):
Financial assets
Total loans and advances—related parties
Financial liabilities
Total debt, excluding capital leases
At December 31, 2016, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $12 million of rights to reclaim cash collateral, respectively. At December 31, 2015, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $1 million of rights to reclaim cash collateral, respectively.
Note 16—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
Issued
Beginning of year
End of year
Held in Treasury
Repurchase of common stock
Preferred Stock
We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued or outstanding at December 31, 2016 or 2015.
Noncontrolling Interests
At December 31, 2016 and 2015, we had $252 million and $320 million outstanding, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. For both periods, the amounts were related to the Darwin LNG and Bayu-Darwin Pipeline operating joint ventures we control.
Repurchase of Common Stock
116
Note 17—Non-Mineral Leases
The company primarily leases drilling equipment and office buildings, as well as ocean transport vessels, tugboats, barges, corporate aircraft, computers and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. For additional information on leased assets under capital leases, see Note 11—Debt.
At December 31, 2016, future minimum rental payments due under noncancelable leases were:
Less: income from subleases
Net minimum operating lease payments
Operating lease rental expense for the years ended December 31 was:
Total rentals
Less: sublease rentals
117
Note 18—Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participant contributions
Plan amendments
Actuarial (gain) loss
Benefits paid
Curtailment
Settlement
Recognition of termination benefits
Foreign currency exchange rate change
Benefit obligation at December 31*
*Accumulated benefit obligation portion of above at December 31:
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Fair value of plan assets at December 31
Funded Status
118
Amounts Recognized in the Consolidated Balance Sheet at December 31
Total recognized
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate
Rate of compensation increase
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Expected return on plan assets
For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost (credit)
119
Sources of Change in Other Comprehensive Income (Loss)
Net gain (loss) arising during the period
Amortization of (gain) loss included in net loss*
Net change during the period
Amortization of prior service cost (credit) included in net loss
*Includes settlement losses recognized in 2016 and 2015.
During the year ended December 31, 2016, there was an amendment to the U.S. other postretirement benefit plan. The benefit obligation decreased by $27 million for changes in the plan made to post-65 retiree medical benefits related to updated cost sharing assumption changes for retirees. The $27 million decrease in the benefit obligation resulted in a corresponding increase in other comprehensive income.
During the year ended December 31, 2015, there were amendments to the U.S. other postretirement benefit plan. The benefit obligation decreased by $303 million for changes in the plan made to retiree medical benefits. The $303 million decrease consists of $149 million related to the discontinuation of all company premium cost-sharing contributions to the post-65 retiree medical plan after December 31, 2025, $91 million related to updated cost sharing assumption changes for retirees, $49 million associated with excluding employees and retirees of Phillips 66 who were not enrolled in a ConocoPhillips retiree medical plan as of July 1, 2015, and $14 million associated with new participants in the post-65 retiree medical plan after December 31, 2015, no longer being eligible for any company premium cost-sharing contributions. The $303 million decrease in the benefit obligation resulted in a corresponding decrease in other comprehensive loss.
Included in accumulated other comprehensive income (loss) at December 31, 2016, were the following before-tax amounts that are expected to be amortized into net periodic benefit cost during 2017:
For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $5,498 million, $5,145 million, and $4,208 million, respectively, at December 31, 2016, and $5,720 million, $5,314 million, and $4,759 million, respectively, at December 31, 2015.
120
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $586 million and $496 million, respectively, at December 31, 2016, and were $639 million and $564 million, respectively, at December 31, 2015.
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
Components of Net Periodic Benefit Cost
Amortization of prior service cost (credit)
Recognized net actuarial loss (gain)
Settlements
Curtailment (gain) loss
Net periodic benefit cost
We recognized pension settlement losses of $202 million in 2016 and $204 million in 2015 as lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of service and interest costs for those plans and led to recognition of settlement losses.
As part of the 2016 and 2015 restructuring programs, we concluded that actions taken during those years resulted in a significant reduction of future services of active employees primarily in the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan. As a result, we recognized an increase in the benefit obligation and a proportionate share of prior service cost from other comprehensive income (loss) as curtailment losses of $15 million and $33 million during the years ended December 31, 2016 and 2015, respectively.
Also as part of the 2016 and 2015 restructuring programs in the U.S. and Europe, we recognized expense for special termination benefits of $15 million during the year ended December 31, 2016, consisting of $14 million in the U.S. and $1 million in Europe, and $124 million during the year ended December 31, 2015, consisting of $46 million in the U.S. and $78 million in Europe. Approximately 62 percent of the 2015 Europe amount was recovered from joint venture partners.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 6.50 percent in 2017 that declines to 5 percent by 2023. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 4 percent in 2017 that increases to 5 percent by 2018. A one-percentage-point change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.
121
Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 57 percent equity securities, 37 percent debt securities and 6 percent real estate. Generally, the plan investments are publicly traded, therefore minimizing liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2016 and 2015.
122
The fair values of our pension plan assets at December 31, by asset class were as follows:
Equity Securities
U.S.
International
Common/collective trusts
Mutual funds
Debt Securities
Government
Derivatives
Real estate
Total in fair value hierarchy
Investments measured at net asset value*
Agency and mortgage-backed securities
Total**
*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a net asset value of $121 million and net payables related to security transactions of $1 million.
123
**Excludes the participating interest in the insurance annuity contract with a net asset value of $125 million and net payables related to security transactions of $32 million.
Level 3 activity was not material for all periods.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2017, we expect to contribute approximately $320 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $110 million to our international qualified and nonqualified pension and postretirement benefit plans.
124
The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid:
Pension
Benefits
2022–2026
Severance Accrual
As a result of the current business environment’s impact on our operating and capital plans, a reduction in our overall employee workforce occurred during 2015 and 2016. Severance accruals of $129 million were recorded in 2016. The following table summarizes our severance accrual activity for the year ended December 31, 2016:
Balance at December 31, 2015
Accruals
Benefit payments
Balance at December 31, 2016
Of the remaining balance at December 31, 2016, $52 million is classified as short-term.
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of approximately 34 investment funds. In 2016, employees who participate in the CPSP and contribute 1 percent of their eligible pay receive a 6 percent company cash match with a potential company discretionary cash contribution of up to 6 percent. Company contributions charged to expense for the CPSP and predecessor plans were $58 million in 2016, $109 million in 2015, and $116 million in 2014.
We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $44 million in 2016, $55 million in 2015, and $66 million in 2014.
Share-Based Compensation Plans
The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2014. Over its 10-year life, the Plan allows the issuance of up to 79 million shares of our common stock for compensation to our employees and directors; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the prior plans that are forfeited, expire or are cancelled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 79 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options. The Human Resources and Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards granted.
125
Awards may be granted in the form of, but not limited to, stock options, restricted stock units and performance share units to employees and nonemployee directors who contribute to the company’s continued success and profitability.
Total share-based compensation expense is measured using the grant date fair value for our equity-classified awards and the settlement date fair value for our liability-classified awards. 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, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture. Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). We 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.
Compensation Expense—Total share-based compensation expense recognized in income (loss) and the associated tax benefit for the years ended December 31 were as follows:
Compensation cost
Tax benefit
Stock Options—Stock options granted under the provisions of the Plan and prior plans permit purchase of our common stock at exercise prices equivalent to the average market price of ConocoPhillips common stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.
The fair market values of the options granted over the past three years were measured on the date of grant using the Black-Scholes-Merton option-pricing model. The weighted-average assumptions used were as follows:
Assumptions used
Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
There were no ranges in the assumptions used to determine the fair market values of our options granted over the past three years.
Due to the separation of our Downstream businesses in 2012, expected volatility for grants of options in 2014 was based on a three-year average historical stock price volatility of a group of peer companies. We believe our historical volatility for periods prior to the separation of our Downstream businesses is no longer relevant in estimating expected volatility. For 2015 and 2016, expected volatility was based on the weighted average blend of the company’s historical stock price volatility from May 1, 2012 (the date of separation of our Downstream businesses) through the stock option grant date and the average historical stock price volatility of a group of peer companies for the expected term of the options.
126
The following summarizes our stock option activity for the year ended December 31, 2016:
Outstanding at December 31, 2015
Granted
Exercised
Forfeited
Expired or cancelled
Outstanding at December 31, 2016
Vested at December 31, 2016
Exercisable at December 31, 2016
The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2016, was 5.74 years, 5.25 years and 4.40 years, respectively. The weighted-average grant date fair value of stock option awards granted during 2015 and 2014 was $9.54 and $10.17, respectively. The aggregate intrinsic value of options exercised during 2015 and 2014 was $10 million and $89 million, respectively.
During 2016, we received $3 million in cash and realized a tax benefit of $4 million from the exercise of options. At December 31, 2016, the remaining unrecognized compensation expense from unvested options was $8 million, which will be recognized over a weighted-average period of 0.91 years, the longest period being 2.13 years.
Stock Unit Program—Generally, restricted stock units are granted annually under the provisions of the Plan. Restricted stock units granted prior to 2013 generally vest ratably in three equal annual installments beginning on the third anniversary of the grant date. Beginning in 2013, restricted stock units granted will vest in an aggregate installment on the third anniversary of the grant date. In addition, beginning in 2012, restricted stock units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award. Upon vesting, the restricted stock units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units are not issued as common stock until the earlier of separation from the company or the end of the regularly scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.
127
The following summarizes our stock unit activity for the year ended December 31, 2016:
Stock Units
Not Vested at December 31, 2016
At December 31, 2016, the remaining unrecognized compensation cost from the unvested units was $105 million, which will be recognized over a weighted-average period of 1.59 years, the longest period being 2.82 years. The weighted-average grant date fair value of stock unit awards granted during 2015 and 2014 was $65.40 and $62.72, respectively. The total fair value of stock units issued during 2015 and 2014 was $316 million and $256 million, respectively.
Performance Share Program—Under the Plan, we also annually grant restricted performance share units (PSUs) to senior management. These PSUs are authorized three years prior to their effective grant date (the performance period). Compensation expense is initially measured using the average fair market value of ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the grant date for stock-settled awards and the settlement date for cash-settled awards.
Stock-Settled
For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee separates from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with five years of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or five years after the grant date (although recipients can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants will vest, absent employee election to defer, upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share of ConocoPhillips common stock per unit.
128
The following summarizes our stock-settled Performance Share Program activity for the year ended December 31, 2016:
At December 31, 2016, the remaining unrecognized compensation cost from unvested stock-settled performance share awards was $3 million, which includes $1 million related to unvested stock-settled performance share awards tied to Phillips 66 stock held by ConocoPhillips employees, which will be recognized over a weighted-average period of 1.82 years, the longest period being 3.98 years. The weighted-average grant date fair value of stock-settled PSUs granted during 2015 and 2014 was $69.25 and $65.46, respectively. The total fair value of stock-settled PSUs issued during 2015 and 2014 was $25 million and $18 million, respectively.
Cash-Settled
In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent employee election to defer, on the earlier of five years after the grant date of the award or the date the employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on the balance sheet. Until settlement occurs, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to compensation expense.
Beginning in 2013, PSUs authorized for future grants will vest upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. These PSUs will be settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. During the performance period, recipients of the PSUs do not receive a quarterly cash payment of a dividend equivalent, but after the performance period ends, until settlement in cash occurs, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to compensation expense.
129
The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2016:
Settled
At December 31, 2016, the remaining unrecognized compensation cost from unvested cash-settled performance share awards was $7 million, which will be recognized over a weighted-average period of 1.75 years, the longest period being 3.13 years. The weighted-average grant date fair value of cash-settled PSUs granted during 2015 and 2014 was $46.54 and $69.23, respectively. The total fair value of cash-settled performance share awards settled during 2015 and 2014 was $6 million and zero, respectively.
From inception of the Performance Share Program through 2013, approved PSU awards were granted after the conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the beginning of new performance periods. These initial target PSU awards will terminate at the end of the performance periods and will be settled after the performance periods have ended. Also in 2014, initial target PSU awards were issued for open performance periods that began in prior years. For the open performance period beginning in 2012, the initial target PSU awards will terminate at the end of the three-year performance period and will be replaced with approved PSU awards. For the open performance period beginning in 2013, the initial target PSU awards will terminate at the end of the three-year performance period and will be settled after the performance period has ended. There is no effect on recognition of compensation expense.
Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued to replace awards held by employees of companies we acquired or issued as part of a compensation program that has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.
The following summarizes the aggregate activity of these restricted shares and units for the year ended December 31, 2016:
Cancelled
At December 31, 2016, all outstanding restricted stock and restricted stock units were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of awards granted during 2015 and 2014 was $58.66 and $71.23, respectively. The total fair value of awards issued during 2015 and 2014 was $3 million and $3 million, respectively.
130
Note 19—Income Taxes
Income taxes charged to income (loss) from continuing operations were:
Income Taxes
Federal
Current
Deferred
Foreign
State and local
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
Deferred Tax Liabilities
PP&E and intangibles
Investment in joint ventures
Inventory
Deferred state income tax
Partnership income deferral
Total deferred tax liabilities
Deferred Tax Assets
Benefit plan accruals
Other financial accruals and deferrals
Loss and credit carryforwards
Total deferred tax assets
Less: valuation allowance
Net deferred tax assets
Net deferred tax liabilities
At December 31, 2016, noncurrent assets and liabilities include deferred taxes of $400 million and $8,949 million, respectively. At December 31, 2015, noncurrent assets and liabilities include deferred taxes of $286 million and $10,999 million, respectively.
131
At December 31, 2016, the components of our loss and credit carryforwards before and after consideration of the applicable valuation allowances are:
U.S. federal net operating loss
U.S. foreign tax credits
U.S. general business credits
State net operating losses and tax credits
Foreign net operating losses and tax credits
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2016, valuation allowances decreased a total of $59 million. This decrease primarily relates to the expected realization of certain deferred tax assets. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will primarily be realized as offsets to reversing deferred tax liabilities.
At December 31, 2016, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $3,720 million. Deferred income taxes have not been provided on this amount, as we do not plan to initiate any action that would require the payment of income taxes. Due to the nature of our structures within the jurisdictions in which we operate, as well as the complex nature of the relevant tax laws, it is not practicable to estimate the amount of additional tax, if any, that might be payable on this income if distributed.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2016, 2015 and 2014:
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Lapse of statute
Included in the balance of unrecognized tax benefits for 2016, 2015 and 2014 were $359 million, $354 million and $348 million, respectively, which, if recognized, would impact our effective tax rate.
At December 31, 2016, 2015 and 2014, accrued liabilities for interest and penalties totaled $54 million, $79 million and $65 million, respectively, net of accrued income taxes. Interest and penalties resulted in a benefit to earnings of $18 million in 2016, a reduction to earnings of $11 million in 2015, and a benefit to earnings of $43 million in 2014.
We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: United Kingdom (2014), Canada (2009), United States (2010) and Norway (2015). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world.
132
As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.
The amounts of U.S. and foreign income (loss) from continuing operations before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Percent of
Pre-Tax Income (Loss)
Income (loss) before income taxes from continuing operations
United States
Federal statutory income tax
Non-U.S. effective tax rates
Foreign tax law change
U.S. fair value election
Enhanced Oil Recovery Credit
State income tax
The decrease in the effective tax rate for 2016 was primarily due to higher income in high tax jurisdictions, lower losses in low tax jurisdictions, and reduced net tax benefit from tax law changes.
The increase in the effective tax rate for 2015 was primarily due to the U.K. tax law change and electing the fair market value method of apportioning interest expense for prior years, discussed below; partially offset by lower income in high tax jurisdictions and the Canadian tax law change, discussed below.
In the United Kingdom, legislation was enacted on September 15, 2016, to decrease the overall U.K. upstream corporation tax rate from 50 percent to 40 percent effective January 1, 2016. As a result, a $161 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the “Income tax provision (benefit)” line on our consolidated income statement.
In the United Kingdom, legislation was enacted on March 26, 2015, to decrease the overall U.K. upstream corporation tax rate from 62 percent to 50 percent effective January 1, 2015. As a result, a $555 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the “Income tax provision (benefit)” line on our consolidated income statement.
In Canada, legislation was enacted on June 29, 2015, to increase the overall Canadian corporation tax rate from 25 percent to 27 percent effective July 1, 2015. As a result, a $129 million net tax expense for revaluing the Canadian deferred tax liability is reflected in the “Income tax provision (benefit)” line on our consolidated income statement.
In December 2015, we filed refund claims for prior years electing the fair market value method of apportioning interest in the United States. As a result, a $185 million tax benefit was recorded in the fourth quarter of 2015.
133
Certain operating losses in jurisdictions outside of the U.S. only yield a tax benefit in the U.S. as a worthless security deduction. For 2016, 2015 and 2014 the amount of the benefit was $60 million, $491 million and $122 million, respectively.
Note 20—Accumulated Other Comprehensive Income
Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:
There were no items within accumulated other comprehensive income (loss) related to noncontrolling interests.
The following table summarizes reclassifications out of accumulated other comprehensive loss during the years ended December 31:
Defined Benefit Plans
See Note 18—Employee Benefit Plans, for additional information.
134
Note 21—Cash Flow Information
Amounts included in continuing operations for the years ended December 31 were:
Noncash Investing and Financing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations*
Cash Payments (Receipts)
Interest
Income taxes**
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased
Short-term investments sold
*Includes $68 million in 2014, primarily related to the impact of U.K. tax law changes on the deductibility of decommissioning costs.
**Net of $585 million and $642 million in 2016 and 2015, respectively, related to refunds received from the Internal Revenue Service.
135
Note 22—Other Financial Information
Interest and Debt Expense
Incurred
Debt
Capitalized
Expensed
Other Income
Interest income
Other, net
Research and Development Expenditures—expensed
Shipping and Handling Costs*
Foreign Currency Transaction (Gains) Losses—after-tax
Properties, Plants and Equipment
Proved properties
Unproved properties
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
Net properties, plants and equipment
136
Note 23—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
Significant transactions with our equity affiliates were:
Operating revenues and other income
Purchases
Operating expenses and selling, general and administrative expenses
Net interest (income) expense*
*We paid interest to, or received interest from, various affiliates. See Note 7—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.
The table above includes transactions with Freeport LNG through the date of the termination agreement and excludes the termination fee. See Note 7—Investments, Loans and Long-Term Receivables, for additional information.
Note 24—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International.
After agreeing to sell our Nigeria business in 2012, we completed the sale in 2014. Results for these operations have been reported as discontinued operations in the applicable periods presented. For additional information, see Note 3—Discontinued Operations.
Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents.
We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at prices that approximate market.
137
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Intersegment eliminations
Consolidated sales and other operating revenues
Depreciation, Depletion, Amortization and Impairments
Consolidated depreciation, depletion, amortization and impairments
138
Equity in Earnings of Affiliates
Consolidated equity in earnings of affiliates
Consolidated income taxes
Consolidated net income (loss) attributable to ConocoPhillips
Investments In and Advances To Affiliates
Consolidated investments in and advances to affiliates
139
Consolidated total assets
Capital Expenditures and Investments
Consolidated capital expenditures and investments
Interest Income and Expense
Sales and Other Operating Revenues by Product
Other*
Consolidated sales and other operating revenues by product
140
Geographic Information
Australia(3)
Other foreign countries
Worldwide consolidated
(1)Sales and other operating revenues are attributable to countries based on the location of the selling operation.
(2)Defined as net PP&E plus investments in and advances to affiliated companies.
(3)Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.
Note 25—New Accounting Standards
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (ASU No. 2014-09), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts.
In August 2015, the FASB issued ASU No. 2015-14, “Deferral of the Effective Date,” which defers the effective date of ASU No. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.
ASU No. 2014-09 was amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts With Customers.”
We will adopt the provisions of ASU No. 2014-09, as amended, with effect from January 1, 2018, and have elected not to early adopt the standard. We intend to adopt the new standard using the modified retrospective approach which we will apply only to contracts within the scope of the standard that are not complete at the date of initial application. Under this approach, we will apply the guidance retrospectively only to the most current period presented in the financial statements. Overall, the impact to our financial statements is expected to be immaterial.
141
In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. While we continue to evaluate the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASU No. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this ASU.
142
Oil and Gas Operations (Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and production operations.
These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.
As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for economic reasons is based on historical 12-month first-of-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 (PSCs), which are 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. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2016, approximately 7 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 23 percent of our total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.
Our reserves disclosures by geographic area include the United States, Canada, Europe (Norway and the United Kingdom), Asia Pacific/Middle East, Africa and Other Areas. Other Areas primarily consists of Russia, which we exited in 2015.
As part of our asset disposition program, we sold our interest in the Nigeria business in July 2014. This business was considered held for sale since the fourth quarter of 2012 and has been reported as discontinued operations for the applicable periods presented. Accordingly, the Results of Operations, Average Sales Prices and Net Production tables included within the supplemental oil and gas disclosures reflect the associated earnings and production as discontinued operations. See Note 3—Discontinued Operations, for additional information.
Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will commence the project within a reasonable time.
Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
143
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers in our business units around the world. As part of our internal control process, each business unit’s reserves processes and controls are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists, finance personnel and a senior representative from DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits, teleconferences and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.
During 2016, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2016, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was the general processes and controls employed by ConocoPhillips in estimating its December 31, 2016, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.
The technical person primarily responsible for overseeing the processes and internal controls used in the preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum Engineers with over 25 years of oil and gas industry experience and has held positions of increasing responsibility in reservoir engineering, subsurface and asset management in the United States and several international field locations.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.
144
Years Ended
December 31
Developed and Undeveloped
End of 2013
Revisions
Improved recovery
Extensions and discoveries
Production
Sales
End of 2014
End of 2015
End of 2016
145
Developed
Undeveloped
Notable changes in proved crude oil reserves in the three years ended December 31, 2016, included:
146
147
Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2016, included:
148
149
Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed in production operations.
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Notable changes in proved natural gas reserves in the three years ended December 31, 2016, included:
150
151
Notable changes in proved bitumen reserves in the three years ended December 31, 2016, included:
152
153
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.
Proved Undeveloped Reserves
We had 1,608 million BOE of proved undeveloped reserves at year-end 2016, compared with 3,024 million BOE at year-end 2015. The following table shows changes in total proved undeveloped reserves for 2016:
Millions of Barrels of
Oil Equivalent
Transfers to proved developed
Revisions, primarily in the oil sands, decreased proved undeveloped reserves due to lower prices. This was partially offset by extensions and discoveries added from ongoing development primarily in the Lower 48, Asia Pacific/Middle East and Alaska.
As a result, at December 31, 2016, our proved undeveloped reserves represented 25 percent of total proved reserves, compared with 37 percent at December 31, 2015. Costs incurred for the year ended December 31, 2016, relating to the development of proved undeveloped reserves were $2.9 billion.
154
A portion of our costs incurred each year relate to development projects where the proved undeveloped reserves will be converted to proved developed reserves in future years.
Approximately 70 percent of our proved undeveloped reserves at year-end 2016 were associated with four major development areas. All of the major development areas are currently producing and are expected to have proved undeveloped reserves convert to proved developed over time, as development activities continue and/or production facilities are expanded or upgraded, and include:
At the end of 2016, approximately 46 percent of our total proved undeveloped reserves are currently scheduled for development five years or more from initial disclosure which are located in the Athabasca oil sands in Canada. The oil sands in Canada consist of the FCCL and Surmont steam-assisted gravity drainage (SAGD) projects. The majority of our remaining proved undeveloped reserves in this area were recorded beginning in 2007. Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated undeveloped reserves are expected to be developed over the life of the project, as additional well pairs are drilled to maintain throughput at the central processing facilities.
Results of Operations
The company’s results of operations from oil and gas activities for the years 2016, 2015 and 2014 are shown in the following tables. Non-oil and gas activities, such as pipeline and marine operations, liquefied natural gas operations, crude oil and gas marketing activities, and the profit element of transportation operations in which we have an ownership interest are excluded. Additional information about selected line items within the results of operations tables is shown below:
155
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Other related expenses
Accretion
Results of operations
156
157
158
Statistics
Net Production
Crude Oil
Europe
Asia Pacific/Middle East
Africa
Other areas
Total continuing operations
Natural Gas Liquids
Equity affiliates—Asia Pacific/Middle East
Consolidated operations—Canada
Equity affiliates—Canada
159
Crude Oil Per Barrel
Total international
Natural Gas Liquids Per Barrel
Bitumen Per Barrel
Natural Gas Per Thousand Cubic Feet
Average sales prices for Alaska crude oil and Asia Pacific/Middle East natural gas above reflect a reduction for transportation costs in which we have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices differ from those discussed in Item 7 of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
160
Average Production Costs Per Barrel of Oil Equivalent*
Total consolidated continuing operations
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada**
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
*Includes bitumen.
**2015 revised to conform to current period presentation.
161
Development and Exploration Activities
The following two tables summarize our net interest in productive and dry exploratory and development wells in the years ended December 31, 2016, 2015 and 2014. A “development well” is a well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field. Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well density or production history have not achieved statistical certainty of results. Excluded from the exploratory well count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada and coalbed methane test wells located in Asia Pacific/Middle East.
Net Wells Completed
Exploratory
Development
162
The table below represents the status of our wells drilling at December 31, 2016, and includes wells in the process of drilling or in active completion. It also represents gross and net productive wells, including producing wells and wells capable of production at December 31, 2016.
*Includes 151 gross and 122 net multiple completion wells.
163
Costs Incurred
Unproved property acquisition
Proved property acquisition
*Certain amounts in Asia Pacific/Middle East equity affiliates have been restated in 2015 and 2014 to remove amounts considered to be non-oil and gas producing activities.
164
Capitalized Costs
Proved property
Unproved property
Accumulated depreciation, depletion and amortization
*Certain amounts in Asia Pacific/Middle East equity affiliates have been restated in 2015 to remove amounts considered to be non-oil and gas producing activities.
165
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs, including dismantlement, and future production costs, including taxes other than income taxes.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions (benefit)
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Future income tax provisions
166
167
168
Sources of Change in Discounted Future Net Cash Flows
Discounted future net cash flows at the beginning of the year
Changes during the year
Revenues less production costs for the year
Net change in prices and production costs
Extensions, discoveries and improved recovery, less estimated future costs
Development costs for the year
Changes in estimated future development costs
Purchases of reserves in place, less estimated future costs
Sales of reserves in place, less estimated future costs
Revisions of previous quantity estimates
Net change in income taxes
Total changes
Discounted future net cash flows at year end
169
Selected Quarterly Financial Data (Unaudited)
Attributable
to ConocoPhillips
For additional information on the commodity price environment, see the Business Environment and Executive Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
170
Supplementary Information—Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
In May 2014, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate amount of various types of debt and equity securities, with certain debt securities guaranteed by ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included in the condensed consolidating financial information.
In 2014, ConocoPhillips received $34.5 billion in dividends from ConocoPhillips Company to settle certain accumulated intercompany balances. This consisted of a $17.5 billion distribution of earnings and a $17 billion return of capital. These transactions had no impact on our consolidated financial statements.
In 2015, ConocoPhillips received a $3.5 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.
In 2016, ConocoPhillips received a $2.3 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.
In 2016, ConocoPhillips Canada Funding Company I repaid $1.25 billion of external debt. This transaction is reflected in our consolidated financial statements.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
171
Income Statement
Equity in earnings (losses) of affiliates
Other income (loss)
Intercompany revenues
Loss from continuing operations before income taxes
Income tax benefit
Net loss
Loss Attributable to ConocoPhillips
Comprehensive Loss Attributable to ConocoPhillips
172
Income from continuing operations before income taxes
Income From Continuing Operations
Net Income Attributable to ConocoPhillips
Comprehensive Income Attributable to ConocoPhillips
173
Balance Sheet
Accounts and notes receivable
Investments, loans and long-term receivables*
Liabilities and Stockholders’ Equity
Other liabilities and deferred credits*
Other common stockholders’ equity
Total Liabilities and Stockholders’ Equity
*Includes intercompany loans.
174
Net Cash Provided by (Used in) Operating Activities
Cash Flows From Investing Activities
Net sales of short-term investments
Long-term advances/loans—related parties
Intercompany cash management
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Statement of Cash Flows
175
Net cash provided by (used in) continuing operating activities
Net purchases of short-term investments
Net cash provided by (used in) continuing investing activities
Net cash provided by (used in) discontinued operations
Net cash used in continuing financing activities
Net Cash Used in Financing Activities
176
We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2016, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, Commercial and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance, Commercial and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of December 31, 2016.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 78 and is incorporated herein by reference.
This report is included in Item 8 on page 80 and is incorporated herein by reference.
177
Information regarding our executive officers appears in Part I of this report on pages 29 and 30.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our internet website at www.conocophillips.com (within the Investors>Corporate Governance section). Any waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our internet website.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 29, 2017, and is incorporated herein by reference.*
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 29, 2017, and is incorporated herein by reference.*
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 29, 2017, and is incorporated herein by reference.*
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 29, 2017, and is incorporated herein by reference.*
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 29, 2017, and is incorporated herein by reference.*
*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2017 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.
178
The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 77, are filed as part of this annual report.
Schedule II—Valuation and Qualifying Accounts, appears below. All other schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.
The exhibits listed in the Index to Exhibits, which appears on pages 180 through 188, are filed as part of this annual report.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
Description
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b)Amounts charged off less recoveries of amounts previously charged off.
(c)Benefit payments.
179
INDEX TO EXHIBITS
180
Number
181
182
183
184
185
186
187
* Filed herewith.
188
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
/s/ Ryan M. Lance
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 21, 2017, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.
/s/ Don E. Wallette, Jr.
/s/ Glenda M. Schwarz
189
/s/ Richard L. Armitage
Richard L. Armitage
/s/ Richard H. Auchinleck
Richard H. Auchinleck
/s/ Charles E. Bunch
Charles E. Bunch
/s/ James E. Copeland, Jr.
James E. Copeland, Jr.
/s/ Gay Huey Evans
Gay Huey Evans
/s/ John V. Faraci
John V. Faraci
/s/ Jody Freeman
Jody Freeman
/s/ Arjun N. Murti
Arjun N. Murti
/s/ Robert A. Niblock
Robert A. Niblock
/s/ Harald J. Norvik
Harald J. Norvik
190