2017
Annual Report
Letter to Shareholders
Dear Fellow Shareholders:
ConocoPhillips has taken a leadership stance with a new approach to the
E&P business, one designed to deliver predictable performance and superior
returns across a wide range of commodity prices. We introduced a disciplined,
returns-focused value proposition in late 2016 and as energy markets began
to recover in 2017, we took several key steps to accelerate and differentiate our
offering to the market.
At the core of our unique value proposition is a clear set of strategic priorities
for cash flow allocation: maintain flat production and pay our dividend; grow
our dividend; maintain a strong balance sheet; pay out 20 to 30 percent of cash from operations to shareholders
annually through the dividend and share buybacks; and invest in high-return projects to expand cash flow. Our
strategy is aimed at creating value even when prices are below $50 per barrel, while also allowing shareholders
to benefit during periods of higher prices.
When we debuted our value proposition we were met with skepticism. Some challenged whether we could
execute our bold set of priorities. Others questioned whether there was a market for an E&P company focused
on returns rather than growth. Just over a year later, we believe we have addressed both concerns. 2017 was
a transformational year for the company as we made strong progress on our strategic priorities. Among our
key achievements, we:
• Reduced exposure to North American natural gas and oil sands assets through dispositions that generated
$16 billion.
• Generated cash from operations that exceeded capital spending by $2.5 billion.
• Returned 61 percent of cash from operations to shareholders through dividends and share buybacks.
• Reduced debt by almost 30 percent to $19.7 billion and improved our credit rating.
• Strengthened our position to deliver improved cash and financial returns even at crude prices below $50 per
barrel WTI.
Importantly, our talented workforce also met or exceeded our 2017 operational goals while achieving one of our
best years of safety performance. We never take safety for granted, nor do we waver from our commitment to
environmental, social and governance (ESG) performance. We took a visible step to sustain our ESG leadership
by announcing a target to reduce greenhouse gas emissions intensity by 5 to 15 percent by 2030.
We believe the market response to our value proposition has been positive. In 2017, we generated a total
shareholder return of 12 percent, which was differential to most other E&P companies. In addition, we note that
there is now growing support across the sector for value propositions like ours, which offer a more disciplined
approach to the business.
By all accounts, 2017 was an exceptional year for ConocoPhillips. We performed well and we’re confident our
value proposition is sound. So, we’re building on that momentum and sticking to our priorities, even as oil prices
recover. As evidence, in January we paid down $2.25 billion of debt. In February, we announced a 7.5 percent
increase in our quarterly dividend and a 33 percent increase in our planned 2018 share buybacks. We took these
actions while maintaining discipline on our low cost of supply investment plan.
I’ll end this note by thanking our shareholders, world-class workforce and board of directors for their contributions
to ConocoPhillips. We can all take pride in the company we have become — stronger, more focused, and built
to thrive in an environment of volatile prices. We intend to make 2018 another strong year by safely executing
and delivering on our commitments.
Ryan M. Lance
Chairman and Chief Executive Officer
Feb. 20, 2018
2017
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
OR
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
01-0562944
(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:
Common Stock, $.01 Par Value
7% Debentures due 2029
Title of each class
Name of each exchange
on which registered
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[x] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act.
[ ] Yes [x] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during
the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[x] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”
“accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [x] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition
period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the
Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2017, the last
business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date
of $43.96, was $54.0 billion.
The registrant had 1,174,577,506 shares of common stock outstanding at January 31, 2018.
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 15, 2018 (Part III)
Documents incorporated by reference:
TABLE OF CONTENTS
Item
Page
PART I
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
1
1
2
3
5
7
8
11
15
18
18
20
25
25
25
26
27
29
30
72
75
174
174
174
175
175
175
175
175
15. Exhibits, Financial Statement Schedules ............................................................................
Signatures ...........................................................................................................................
176
188
PART I
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to
refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and
Properties, contain forward-looking statements including, without limitation, statements relating to our plans,
strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the
Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,”
“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,”
“expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar
expressions identify forward-looking statements. The company does not undertake to update, revise or correct
any forward-looking information unless required to do so under the federal securities laws. Readers are
cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures
under the heading “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on
page 70.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on
proved reserves and production of liquids and natural gas. ConocoPhillips was incorporated in the state of
Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc.
and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30,
2002.
In April 2012, ConocoPhillips completed the separation of the downstream business into an independent,
publicly traded energy company, Phillips 66.
Headquartered in Houston, Texas, we have operations and activities in 17 countries. Our diverse 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, 2017, ConocoPhillips employed approximately 11,400 people worldwide.
We operate in a commodity-price driven industry, subject to volatility. In line with this view, we set our
operating plan for 2017, defining our cash allocation priorities which would be reinforced and partly funded by
sales of noncore assets during the year. In November 2016, we announced our plan to generate $5 billion to
$8 billon of proceeds over two years by optimizing our portfolio to focus on value-preserving, low cost-of-
supply projects that strategically fit our development plans. In 2017, our total consideration from asset
dispositions was approximately $16 billion. We disposed of assets including our 50 percent nonoperated
interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada
gas assets, and our interest in the San Juan Basin gas asset. Proceeds from dispositions were directed towards
allocation priorities and our asset sales, see the Business Environment and Executive Overview section within
Management’s Discussion and Analysis and Note 4—Assets Held for Sale, Sold or Acquired, in the Notes to
Consolidated Financial Statements, respectively.
1
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 23—Segment Disclosures and Related
Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on
a worldwide basis. At December 31, 2017, 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:
(cid:120) Proved worldwide crude oil, natural gas liquids, natural gas and bitumen reserves.
(cid:120) Net production of crude oil, natural gas liquids, natural gas and bitumen.
(cid:120) Average sales prices of crude oil, natural gas liquids, natural gas and bitumen.
(cid:120) Average production costs per barrel of oil equivalent (BOE).
(cid:120) Net wells completed, wells in progress and productive wells.
(cid:120) Developed and undeveloped acreage.
The following table is a summary of the proved reserves information included in the “Oil and Gas Operations”
disclosures following the Notes to Consolidated Financial Statements. Approximately 77 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
Consolidated operations
Equity affiliates
Total Natural Gas Liquids
Natural gas
Consolidated operations
Equity affiliates
Total Natural Gas
Bitumen
Consolidated operations
Equity affiliates
Total Bitumen
Total consolidated operations
Total equity affiliates
Total company
Millions of Barrels of Oil Equivalent
2017
2016
2,322
83
2,405
354
45
399
1,267
717
1,984
250
-
250
4,193
845
5,038
2,047
88
2,135
457
47
504
1,807
730
2,537
159
1,089
1,248
4,470
1,954
6,424
2015
2,270
93
2,363
508
50
558
1,988
878
2,866
687
1,706
2,393
5,453
2,727
8,180
2
Total production, including Libya, of 1,377 thousand barrels of oil equivalent per day (MBOED) decreased
12 percent in 2017 compared with 2016. The decrease in total average production primarily resulted from
noncore asset dispositions, including our Canada and San Juan transactions in 2017 and the sale of our interest
in the Block B production sharing contract (PSC) in Indonesia in 2016, and normal field decline. The decrease
in production was partly offset by production from major developments, including tight oil plays in the Lower
48; Malikai and the Kebabangan gas field in Malaysia; Surmont in Canada; and APLNG in Australia.
Improved drilling and well performance in Alaska, Norway and China also partly offset the decrease in
production. Excluding Libya, our 2017 production was 1,356 MBOED. Adjusted for the impact of closed and
planned dispositions of 191 MBOED in 2017 and 434 MBOED in 2016 and Libya, underlying production
increased 32 MBOED, or 3 percent, compared with 2016.
Our worldwide annual average realized price was $39.19 per BOE in 2017, an increase of 38 percent compared
with $28.35 per BOE in 2016, reflecting higher average realized prices across all commodities. Our
worldwide annual average crude oil price increased 27 percent in 2017, from $40.86 per barrel in 2016 to
$51.96 per barrel in 2017. Additionally, our worldwide annual average natural gas liquids prices increased
51 percent, from $16.68 per barrel in 2016 to $25.22 per barrel in 2017. Our worldwide annual average natural
gas price increased 36 percent, from $3.00 per MCF in 2016 to $4.07 per MCF in 2017. Average annual
bitumen prices also increased 48 percent, from $15.27 per barrel in 2016 to $22.66 per barrel in 2017.
ALASKA
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and natural
gas liquids. We are the largest crude oil producer in Alaska and have major ownership interests in two of
North America’s largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have
a 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 1 million net
undeveloped acres at year-end 2017. Alaska operations contributed 22 percent of our worldwide liquids
production and less than 1 percent of our natural gas production.
Interest
Operator
MBD *
MMCFD **
Liquids
2017
Natural Gas
36.1 %
52.2–55.5
78.0
BP
ConocoPhillips
ConocoPhillips
88
53
40
181
5
1
1
7
Total
MBOED
89
53
40
182
Average Daily Net Production
Greater Prudhoe Area
Greater Kuparuk Area
Western North Slope
Total Alaska
*Thousands of barrels per day.
**Millions of cubic feet per day.
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point
McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large
waterflood and enhanced oil recovery operation, as well as a gas plant which processes natural gas 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.
3
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which consists of the Kuparuk Field and four satellite fields: Tarn,
Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay. Field installations
include three central production facilities which separate oil, natural gas and water, as well as a separate
seawater treatment plant. Development drilling at Kuparuk consists of rotary-drilled wells and horizontal
multi-laterals from existing well bores utilizing coiled-tubing drilling.
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 was achieved in the fourth quarter of 2017.
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three
satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. In 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 continued drilling additional wells using the
available well slots on the pad.
The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was formed in 2008. In
2017, we began construction in the unit, which is currently planned to have two drill sites; Greater Mooses
Tooth #1 and #2, with expected first oil in 2018 and 2021, respectively.
Cook Inlet Area
In January 2018, we sold our interest in the Kenai LNG Facility in the Cook Inlet Area. The facility, which
consisted of a 1.6 million-tons-per-year capacity plant, as well as docking and loading facilities for LNG
tankers, had no LNG export program in 2017 due to market conditions.
Point Thomson
In the first quarter of 2017, we recorded an asset impairment and assigned our 4.9 percent interest in the Point
Thomson unit, located approximately 60 miles east of Prudhoe Bay, to the other owners of the field.
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. AGDC is continuing to progress the project and
has recently signed several Memorandums of Understanding with various potential LNG buyers in Asia. We
remain supportive of AGDC’s efforts to advance the project and intend to make our equity gas available for
sale to the project at mutually agreed, commercially reasonable terms.
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the National Petroleum Reserve-Alaska,
continued throughout 2017 with the acquisition of 3-D seismic which is currently being processed. In 2018,
we will continue appraisal of the discovery with drilling of additional wells. Further exploration of other state
and federal leases is planned in 2018.
We were successful in state and federal lease sales in the North Slope in the fourth quarter of 2017, where we
were the high bidder on 13 tracts for a total of approximately 78,000 net acres.
4
Acquisition
In January 2018, we entered into an agreement to acquire certain oil and gas assets in Alaska. The acquisition
is subject to regulatory approval. We will have a 100 percent interest in approximately 1.2 million acres of
exploration and development lands, including the Willow Discovery. For additional information, see Note 4—
Assets Held for Sale, Sold or Acquired, in the Notes to Consolidated Financial Statements.
Transportation
We transport the petroleum liquids produced on the North Slope to south central Alaska through an 800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS). We have a 29.1 percent ownership interest in
TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled tankers, and charters third-party vessels as necessary.
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the United States.
LOWER 48
The Lower 48 segment consists of operations located in the 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. We disposed of several noncore assets within the Lower 48 in 2017, including our interests in
the San Juan Basin and the Panhandle. We hold 10.4 million net onshore and offshore acres in the Lower 48.
In 2017, the Lower 48 contributed 30 percent of our worldwide liquids production and 27 percent of our
natural gas production.
Average Daily Net 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
Interest
Operator
Liquids
MBD
2017
Natural Gas
MMCFD
Total
MBOED
Various %
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
107
15
5
127
41
4
4
49
56
-
2
15
73
249
155
13
11
179
132
34
91
257
56
84
3
319
462
898
133
17
7
157
63
10
19
92
65
14
3
68
150
399
Onshore
We hold 10.4 million net acres of onshore conventional and unconventional acreage in the Lower 48, the
majority of which is either held by production or owned by the company. Our unconventional holdings total
approximately 1.8 million net acres in the following areas:
(cid:120) 630,000 net acres in the Bakken, located in North Dakota and eastern Montana.
(cid:120) 210,000 net acres in the Eagle Ford, located in South Texas.
(cid:120) 134,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
5
(cid:120) 98,000 net acres in the Niobrara, located in northeastern Colorado.
(cid:120) 66,000 net acres in the Barnett, located in north central Texas.
(cid:120) 639,000 net acres in other unconventional exploration plays.
The majority of our 2017 onshore production originated from the Eagle Ford; San Juan, which we disposed of
during the year; Bakken; and Permian. Onshore activities in 2017 were centered mostly on continued
development of assets, with an emphasis on areas with low cost of supply, particularly in growing
unconventional plays. The 2017 drilling activity levels increased relative to 2016 due to higher capital
spending. Our major focus areas in 2017 included the following:
(cid:120) Eagle Ford—The Eagle Ford continued full-field development in 2017. We operated six rigs on
average in 2017, resulting in 133 operated wells drilled and 94 operated wells brought online.
Production decreased 17 percent in 2017 compared with 2016, and reached a net peak of
164 MBOED, compared with 176 MBOED in 2016.
(cid:120) Bakken—We operated four rigs throughout the year in the Bakken. We continued our pad drilling
with 87 operated wells drilled during the year and 64 operated wells brought online. We achieved net
peak production of 75 MBOED in 2017, compared with 72 MBOED in 2016.
(cid:120) Permian Basin—The Permian Basin is an area where we are leveraging our conventional legacy
position by utilizing new technology to improve the ultimate recovery and value from these fields.
This technology should also identify new, unconventional plays across the region. We hold
approximately 1 million net acres in the Permian, which includes 134,000 net unconventional acres.
The Permian Basin produced 63 MBOED in 2017, staying essentially flat with 2016, including
19 MBOED of unconventional production.
We completed the sale of our interests in the San Juan Basin on July 31, 2017, and Panhandle assets on
September 29, 2017. Production from the assets sold was 74 MBOED, approximately 19 percent of total
Lower 48 segment production in 2017. For additional information on our asset dispositions, see Note 4—
Assets Held for Sale, Sold or Acquired, in the Notes to Consolidated Financial Statements.
Gulf of Mexico
At year-end 2017, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one
operated field and three fields operated by co-venturers, totaling approximately 68,000 net acres, including:
(cid:120) 75 percent operated working interest in the Magnolia Field in Garden Banks Blocks 783 and 784.
(cid:120) 15.9 percent nonoperated working interest in the unitized Ursa Field located in the Mississippi Canyon
Area.
(cid:120) 15.9 percent nonoperated working interest in the Princess Field, a northern subsalt extension of the
Ursa Field.
(cid:120) 12.4 percent nonoperated working interest in the unitized K2 Field, comprised of seven blocks in the
Green Canyon Area.
Exploration
(cid:120) Conventional Exploration
At December 31, 2017, we held approximately 5,000 net acres in the deepwater Gulf of Mexico.
Our 30 percent nonoperated working interest in the Shenandoah discovery was announced in 2009. In
early 2017, the sixth Shenandoah well, Shenandoah WR52-3, reached total depth and was followed by
the drilling of a sidetrack well from Shenandoah WR52-3. Following the suspension of appraisal
activity by the operator during the year, we recorded dry hole and leasehold impairment expense for
the entire development. On December 19, 2017, we elected to withdraw from the Shenandoah leases.
The withdrawal was effective February 17, 2018.
6
(cid:120) Unconventional Exploration
Our onshore focus areas include the Niobrara in the Denver-Julesburg Basin and the Permian in the
Delaware Basin, as well as several emerging plays. We continue to assess and appraise these and
other unconventional opportunities. In 2016 and 2017, we drilled a total of five operated
unconventional wells in the Powder River Basin, four of which were expensed as dry holes in
November 2017. The fifth Powder River Basin well was expensed as a dry hole in January 2018.
Facilities
Golden Pass LNG Terminal
We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass
Pipeline, with a combined net book value of approximately $247 million at December 31, 2017. 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.
Other
(cid:120) Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a
246 million cubic-feet-per-day capacity natural gas processing facility in Lysite, Wyoming.
(cid:120) Helena Condensate Processing Facility—We operate and own the Helena Condensate Processing
Facility, a 110,000 barrel-per-day condensate processing plant located in Kenedy, Texas.
(cid:120) Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the
Sugarloaf Condensate Processing Facility, a 30,000 barrel-per-day condensate processing plant
located near Pawnee, Texas.
(cid:120) Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate
Processing Facility, a 15,000 barrel-per-day condensate processing plant located in Kenedy, Texas.
CANADA
Our Canadian operations mainly consist of an oil sands development in the Athabasca Region of northeastern
Alberta and a liquids-rich unconventional play in western Canada. In 2017, operations in Canada contributed
16 percent of our worldwide liquids production and 6 percent of our natural gas production.
2017
Natural
Interest
Operator
MBD MMCFD MBD
Liquids
Gas Bitumen
Total
MBOED
Average Daily Net Production
Western Canada
Surmont
Foster Creek
Christina Lake
Total Canada
Various %
50.0
50.0
50.0
Various
ConocoPhillips
Cenovus
Cenovus
12
-
-
-
12
187
-
-
-
187
-
59
26
37
122
43
59
26
37
165
7
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Production from the assets sold was
103 MBOED, approximately 62 percent of the total Canada segment production in 2017. For additional
information on our asset dispositions, see Note 4—Assets Held for Sale, Sold or Acquired, in the Notes to
Consolidated Financial Statements.
Oil Sands
Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-
assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the
heavy bitumen, which is recovered and pumped to the surface for further processing. We hold approximately
0.6 million net acres of land in the Athabasca Region of northeastern Alberta.
Surmont—The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta.
Surmont is a 50/50 joint venture with Total S.A. The second phase of the Surmont project achieved first
production in 2015, and production continued to ramp up in 2017.
Exploration
We hold exploration acreage in three areas of Canada: onshore western Canada, the Mackenzie Delta/Beaufort
Sea Region and the Arctic Islands. Our primary exploration focus is on unconventional plays in western
Canada.
(cid:120) Unconventional Exploration
We hold approximately 0.1 million net acres in the emerging Montney play in northeast British
Columbia and 0.2 million net acres in Canol Northwest Territories. Our Montney activity in 2017
included completing two and bringing onstream six appraisal wells and acquiring approximately
27,000 additional net acres. Late appraisal drilling activity will continue in 2018 to further explore the
area’s resource potential.
(cid:120) Conventional Exploration
Surrender of Interest documents for our 30 percent nonoperated working interest in six exploration
licenses in the Shelburne Basin, offshore Nova Scotia, were submitted on December 15, 2017, to
initiate the exit process, following previously announced results of the two-well exploration drilling
campaign at Cheshire and Monterey Jack.
EUROPE AND NORTH AFRICA
The Europe and North Africa segment consists of operations and exploration activities in Norway, the United
Kingdom and Libya. In 2017, operations in Europe and North Africa contributed 18 percent of our worldwide
liquids production and 15 percent of natural gas production.
Norway
Average Daily Net Production
Greater Ekofisk Area
Alvheim
Heidrun
Other
Total Norway
Interest
Operator
35.1 % ConocoPhillips
Aker BP
20.0
Statoil
24.0
Statoil
Various
2017
Liquids Natural Gas
Total
MBD MMCFD MBOED
57
15
13
16
101
50
13
30
107
200
65
17
18
34
134
8
The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway, in the North Sea,
and comprises three producing fields: Ekofisk, Eldfisk and Embla. Crude oil is exported to Teesside, England,
and the natural gas is exported to Emden, Germany. The Ekofisk and Eldfisk fields consist of several
production platforms and facilities, including the Ekofisk South and Eldfisk II developments which achieved
first production in 2013 and 2015, respectively. Continued development drilling in the Greater Ekofisk Area
will contribute additional production over the coming years, as additional wells come online.
The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, and
consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced
crude oil is exported via shuttle tankers, and natural gas is transported to the Scottish Area Gas Evacuation
(SAGE) terminal at St. Fergus, Scotland, through the SAGE pipeline.
The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and
exported via shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of
crude oil production, some gas is transported to Europe via gas processing terminals in Norway, while the
remainder is transported 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,
as well as the Aasta Hansteen development in the Norwegian Sea. The operator is planning for first gas for
Aasta Hansteen by late 2018.
Exploration
In 2017, we participated in the Korpfjell Well in the Barents Sea and the Carmen Well in the Heidrun Area of
Norway, both of which made gas discoveries. The Carmen Well was considered a discovery and is currently
under evaluation, while the Korpfjell Well is not considered commercial. In 2017, we were awarded four new
exploration licenses including the PL865, PL888, PL890 and PL891; and two acreage additions PL053C and
PL782SC. Additionally, two new licenses, PL775 and PL626, were captured through farm-in.
Transportation
We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil
from Ekofisk to a crude oil stabilization and natural gas liquids processing facility in Teesside, England.
United Kingdom
2017
Interest
Operator
Average Daily Net Production
Britannia
Britannia Satellites
J-Area
Southern North Sea
East Irish Sea
Other
Total United Kingdom
*Includes the Chevron-operated Alder Field, ConocoPhillips equity 26.3%.
58.7 % ConocoPhillips
26.3–87.5 * ConocoPhillips
ConocoPhillips
32.5–36.5
ConocoPhillips
Various
Spirit Energy
100.0
Various
Various
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
3
13
9
-
-
4
29
68
84
60
46
14
4
276
14
27
19
8
2
5
75
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
9
through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish, Brodgar, Enochdhu
and Alder, produce via subsea manifolds and pipelines linked to the Britannia Platform.
The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The
J-Area gas is processed on the Judy Platform and transported through the Central Area Transmission System
Pipeline, while liquids are transported to Teesside through the Norpipe system. A J-Area development drilling
campaign commenced in 2017, which is expected to provide additional volumes in the coming years as wells
are brought online.
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. 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 expected in 2018.
Transportation
We operate the Teesside oil and Theddlethorpe gas terminals in which we have 29.3 percent and 50 percent
ownership interests, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal,
operated by a third party.
Libya
Average Daily Net Production
Waha Concession
Total Libya
Interest
Operator
16.3 %
Waha Oil Co.
2017
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
20
20
8
8
21
21
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. In 2017, we had 17 crude liftings from Es Sider. We expect a gradual, continued ramp-up in
activity.
10
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 2017, operations in the Asia Pacific and Middle East segment contributed 14 percent of our worldwide
liquids production and 52 percent of natural gas production.
Australia and Timor Sea
2017
Average Daily Net Production
Australia Pacific LNG
Bayu-Undan
Athena/Perseus
Total Australia and Timor Sea
Interest
Operator
ConocoPhillips/
Origin Energy
ConocoPhillips
ExxonMobil
37.5 %
56.9
50.0
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
-
10
-
10
638
233
34
905
106
49
6
161
Australia Pacific LNG
Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy Limited and China
Petrochemical Corporation (Sinopec), is focused on producing coalbed methane (CBM) from the Bowen and
Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for
export. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream
LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.
Two fully subscribed 4.5-million-metric-tonnes-per-year LNG trains have been completed. Approximately
3,900 net wells are ultimately 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. APLNG Train 2 achieved
first production in the third quarter of 2016. The LNG is being sold to Sinopec under 20-year sales agreements
for 7.6 million metric tonnes of LNG per year, and Japan-based Kansai Electric Power Co., Inc. under a
20-year sales agreement for approximately 1 million metric tonnes of LNG per year.
APLNG has an $8.5 billion project finance facility, which was fully drawn down and had an outstanding
balance of $7.9 billion at December 31, 2017. 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. In August 2017, we reached financial completion for Train 2, which
removed the remaining guarantee. For additional information, see Note 2—Variable Interest Entities (VIEs),
Note 5—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, in the Notes to
Consolidated Financial Statements.
Bayu-Undan
The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back into the reservoir. In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year capacity Darwin LNG Facility. Produced
11
natural gas is piped to the Darwin LNG Plant, where it is converted into LNG before being transported to
international markets. In 2017, we sold 150 billion gross cubic feet of LNG primarily to utility customers in
Japan.
A continuation of the Bayu-Undan Phase Three Development has been sanctioned with internal, joint venture
and regulatory approval in March 2017. The project premise consists of one subsea and two platform wells,
with drilling to commence in April 2018. Production is expected to commence in the third quarter of 2018.
Athena/Perseus
The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the
Perseus Field, which straddles the boundary with WA-1-L, an adjoining license area. Natural gas is produced
from these licenses, which are due to expire in 2019.
Greater Sunrise
We have a 30 percent interest in the Greater Sunrise natural gas and condensate field located in the Timor Sea.
Timor-Leste and Australia through engagement in a conciliation process under the United Nations Convention
on the Law of the Sea have reached agreement on the central elements of a maritime boundary delimitation
between them in the Timor Sea. The Governments’ agreement, to be formalized in a new treaty, constitutes a
package that addresses boundaries, the legal status of the Greater Sunrise gas field, the establishment of a
Special Regime for Greater Sunrise, a pathway to development of the resource and the sharing of resulting
revenue. Discussions are ongoing between the two Governments and the Sunrise co-venturers with respect to
the development concept for Greater Sunrise. Until the Governments and the Sunrise co-venturers are aligned
on a development concept, activities are currently restricted to compliance and social investment, maintaining
relationships and continued engagement with the Governments for a future development option.
Exploration
(cid:120) Conventional Exploration
We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which we
own a 40 percent interest in permits WA-315-P, WA-398-P and TP 28, of the Greater Poseidon Area.
The TP 28 Western Australia State exploration permit was granted for five years from January 2017,
with a 40 percent working interest and was excised from the existing permits as agreed between state
and federal regulators. Phase I of the Browse Basin drilling campaign in 2009/2010 resulted in three
discoveries in the Greater Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the
drilling campaign resulted in five additional discoveries: Boreas-1, Zephyros-1, Proteus-1 SD2,
Poseidon-North-1 and Pharos-1. All wells have been 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 3-D seismic survey was completed over the Barossa and Caldita fields in 2016. The drilling of the
Barossa-5 and Barossa-6 appraisal wells was completed in 2017 with good quality, gas-bearing
reservoir intersected at both. Additionally, the retention lease over the Barossa Discovery was
renewed during the year.
Indonesia
Average Daily Net Production
South Sumatra
Total Indonesia
Interest
Operator
45.0–54.0%
ConocoPhillips
12
2017
Natural
Total
Gas
MBD MMCFD MBOED
Liquids
2
2
308
308
53
53
We operate three 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.
South Sumatra
The Corridor PSC consists of five oil fields and seven natural gas fields in various stages of development.
Natural gas is supplied from the Grissik and Suban gas processing plants to the Duri steamflood in central
Sumatra and to markets in Singapore, Batam and West Java. Production from the South Jambi “B” PSC has
reached depletion and field development has been suspended.
Exploration
We have a 60 percent working interest in the Kualakurun PSC, located in Central Kalimantan, which was
signed in May 2015. This block has an area of approximately 2 million gross acres. During 2017, we acquired
2-D seismic data in the area.
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas
Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.
China
Average Daily Net Production
Penglai
Panyu
Total China
Interest
Operator
49.0 %
24.5
CNOOC
CNOOC
2017
Natural
Total
Gas
MBD MMCFD MBOED
Liquids
30
8
38
-
-
-
30
8
38
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 19 wells completed and brought online through December 2017.
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.
Exploration
In 2017, we participated in a successful appraisal well in the Penglai Field, which will support future
development plans. In late 2017, we began a full-field 3-D seismic program at Penglai, covering Phase 3 and
other future development opportunities. The program is expected to continue in 2018.
13
Malaysia
Average Daily Net Production
Siakap North-Petai
Gumusut
KBB
Malikai
Total Malaysia
Interest
Operator
21.0 %
29.0
30.0
35.0
Murphy
Shell
KPOC
Shell
2017
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
3
29
3
12
47
1
-
111
-
112
3
29
22
12
66
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.
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.
First production from the Malikai oil field was achieved in December 2016, with estimated net annual peak
production of 21 MBOED expected in 2018. We own a 35 percent interest in Malikai. The Limbayong-2
appraisal well was drilled in 2013 and resulted in an oil discovery. The well was expensed in 2017.
Block J
First production from the Gumusut Field occurred from an early production system in 2012. Production from
a permanent, semi-submersible floating production vessel was achieved in October 2014. Our ownership in
the Gumusut Field is currently at 29 percent following the finalization of the unitization with Brunei and a
redetermination of the Block J and Block K Malaysia Unit, both 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. Development options for the Kamunsu East gas field are
being evaluated.
Exploration
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 drilled and expensed as a dry hole in 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.
We completed a 3-D seismic survey in Block SK 313 and Block WL4-00 in 2017. Further exploration drilling
is expected to occur in 2018.
14
Brunei
Exploration
We have a 6.25 percent working interest in the deepwater Block CA-2 PSC. 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.
Qatar
Average Daily Net Production
QG3
Total Qatar
Interest
Operator
30.0 %
Qatargas Operating
Company Limited
2017
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
21
21
369
369
83
83
QG3 is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips
(30 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 consists of upstream natural gas production facilities,
which produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over
a 25-year life, in addition to a 7.8 million gross tonnes-per-year LNG facility. LNG is shipped in leased LNG
carriers destined for sale globally.
QG3 executed the development of the onshore and offshore assets as a single integrated development with
Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint
development of offshore facilities situated in a common offshore block in the North Field, as well as the
construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and
QG4 joint ventures. Production from the LNG trains and associated facilities is combined and shared.
OTHER INTERNATIONAL
The Other International segment includes exploration activities in Colombia and Chile.
Colombia
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 and
testing in 2017. Socialization and environmental permitting activities are expected to continue throughout
2018.
In July 2017, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. executed an
Additional Contract for the exploration and exploitation of unconventional reservoirs in an area identified as
the VMM-2 Block. As a result, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A.
also executed a joint operating agreement. We have an 80 percent operated working interest in the block
which extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block.
In 2017, we relinquished our 70 percent nonoperated interests in the deep rights in the Santa Isabel Block and
terminated the exploration and production contract for the VMM27 Block, both in the Middle Magdalena
Basin.
15
Chile
Exploration
We have a 49 percent interest in the Coiron Block located in the Magallanes Basin in southern Chile. In
December 2017, two wells drilled in 2016, were expensed as dry holes.
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 12—Contingencies and
Commitments, in the Notes to Consolidated Financial Statements.
OTHER
Marketing Activities
Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural
gas, crude oil, bitumen, natural gas liquids and LNG. Marketing activities are performed through offices in the
United States, Canada, Europe and Asia. In marketing our production, we attempt to minimize flow
disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made
at prevailing market prices at the time of sale. We also purchase and sell third-party volumes to better position
the company to satisfy customer demand while fully utilizing transportation and storage capacity.
Natural Gas
Our natural gas production, along with third-party purchased gas, is primarily marketed in the United States,
Canada, Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution
companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas
companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport
natural gas via firm and interruptible transportation agreements to major market hubs.
Crude Oil, Bitumen and Natural Gas Liquids
Our crude oil, bitumen and natural gas liquids revenues are derived from production in the United States,
Canada, Australia, Asia, Africa and Europe. These commodities are primarily sold under contracts with prices
based on market indices, adjusted for location, quality and transportation.
LNG
LNG marketing efforts are focused on equity LNG production facilities located in Australia and Qatar. LNG
is primarily sold under long-term contracts with prices based on market indices.
Energy Partnerships
Marine Well Containment Company (MWCC)
We are a founding member of the MWCC, a non-profit organization formed in 2010, which provides well
containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC’s containment system
meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment
system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico. For additional
information, see Note 2—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.
Subsea Well Response Project (SWRP)
In 2011, we, along with several leading oil and gas companies, launched the SWRP, a non-profit organization
based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international
subsea well control incidents. Through collaboration with Oil Spill Response Limited, a non-profit
organization in the United Kingdom, subsea well intervention equipment is available for the industry to use in
the event of a subsea well incident. This complements the work being undertaken in the United States by
MWCC.
16
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.
17
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, 2017. No difference exists between our estimated total proved reserves
for year-end 2016 and year-end 2015, which are shown in this filing, and estimates of these reserves shown in
a filing with another federal agency in 2017.
DELIVERY COMMITMENTS
We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements,
some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also
enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the
spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed
to deliver approximately 1.7 trillion cubic feet of natural gas, including approximately 303 billion cubic feet
related to the noncontrolling interests of consolidated subsidiaries, and 99 million barrels of crude oil in the
future. These contracts have various expiration dates through the year 2029. We expect to fulfill the majority
of these delivery commitments with proved developed reserves. In addition, we anticipate using proved
undeveloped reserves and spot market purchases to fulfill any remaining commitments. See the disclosure on
“Proved Undeveloped Reserves” in the “Oil and Gas Operations” section following the Notes to Consolidated
Financial Statements, for information on the development of proved undeveloped reserves.
COMPETITION
We compete with private, public and state-owned companies in all facets of the E&P business. Some of our
competitors are larger and have greater resources. Each of our segments is highly competitive, with no single
competitor, or small group of competitors, dominating.
We compete with numerous other companies in the industry, including state-owned companies, to locate and
obtain new sources of supply and to produce oil, bitumen, natural gas liquids and natural gas in an efficient,
cost-effective manner. Based on statistics published in the September 4, 2017, issue of the Oil and Gas
Journal, we were the third-largest U.S.-based oil and gas company in worldwide liquids production and
reserves, and the fourth-largest U.S.-based oil and gas company in worldwide natural gas production and
reserves in 2016. 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 2017, we held a total of 734 active patents in 47 countries worldwide, including 328 active U.S.
patents. During 2017, we received 32 patents in the United States and 40 foreign patents. Our products and
processes generated licensing revenues of $79 million in 2017. 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 $100 million,
$116 million and $222 million in 2017, 2016 and 2015, 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
18
process and occupational safety. In support of the goal of zero incidents, HSE milestones and criteria are
established annually to drive strong safety performance. Progress toward these milestones and criteria are
measured and reported. HSE audits are conducted on business functions periodically, and improvement
actions are established and tracked to completion. We also have detailed processes in place to address
sustainable development in our economic, environmental and social performance. Our processes, related tools
and requirements focus on water, biodiversity and climate change, as well as social and stakeholder issues.
The environmental information contained in Management’s Discussion and Analysis of Financial Condition
and Results of Operations on pages 61 through 64 under the captions “Environmental” and “Climate Change”
is incorporated herein by reference. It includes information on expensed and capitalized environmental costs
for 2017 and those expected for 2018 and 2019.
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.
19
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 2017 for Brent crude oil, WTI crude oil, Henry Hub natural
gas and our realized natural gas liquids all decreased by at least 30 percent when compared with 2014 despite
having improved by at least 18 percent when compared with 2016. 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 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 three years, we
recognized several impairments, which are described in Note 8—Impairments and the “APLNG” section of
Note 5—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 and repurchase shares 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:
(cid:120) Cash available for distribution.
(cid:120) Our results of operations and anticipated future results of operations.
(cid:120) Our financial condition, especially in relation to the anticipated future capital needs of our properties.
(cid:120) The level of reserves we establish for future capital expenditures.
(cid:120) The level of distributions paid by comparable companies.
(cid:120) Our operating expenses.
(cid:120) Other factors our Board of Directors deems relevant.
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.
20
Additionally, our share repurchase program does not obligate us to acquire any specific number of shares. Any
downward revision in our distribution or share repurchase program could have a material adverse effect on the
market price of our common stock.
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. In addition, although we anticipate we will be able to repay our existing
indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able
to do so. Our ability to obtain additional financing, or refinance our existing indebtedness when it matures or
in accordance with our stated plans, 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. For example, due to the
significant decline in prices for crude oil, bitumen, natural gas, natural gas liquids and LNG in 2015, and the
expectation that these prices could remain depressed, 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 in
2016. 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 volatility 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.
21
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.
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:
(cid:120) The discharge of pollutants into the environment.
(cid:120) Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and greenhouse gas
emissions.
(cid:120) Carbon taxes.
(cid:120) The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous
and nonhazardous wastes.
(cid:120) The dismantlement, abandonment and restoration of our properties and facilities at the end of their
useful lives.
(cid:120) Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil
sands reservoirs and tight oil plays.
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation
expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are
not ultimately reflected in the prices of our products and services, our business, financial condition, results of
operations and cash flows in future periods could be materially adversely affected.
Although our business operations are designed and operated to accommodate expected climatic conditions, to
the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather
22
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.
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, including changes resulting from the implementation and interpretation of the Tax
Cuts and Jobs Act, 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 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 2017, and 45 percent of our proved reserves, as of December 31, 2017, 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
23
associated with any acquisitions or joint ventures could have a material adverse effect on the financial
condition or results of operations of our joint ventures and, in turn, our business and operations.
We 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.
As part of our disposition strategy, on May 17, 2017, we completed the sale of our 50 percent nonoperated
interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.
Consideration for the transaction included 208 million Cenovus Energy common shares. We may not be able
to liquidate the shares issued to us by Cenovus Energy at prices we deem acceptable, or at all.
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.
24
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental
authorities under federal, state and local laws regulating the discharge of materials into the environment for
this reporting period. The following proceedings include those matters that arose during the fourth quarter of
2017, as well as matters previously reported in our 2016 Form 10-K and our first-, second- and third-quarter
2017 Form 10-Qs that were not resolved prior to the fourth quarter of 2017. 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.
Matters Previously Reported—Phillips 66
In May 2012, the Illinois Attorney General's office filed and notified ConocoPhillips of a complaint with
respect to operations at the Phillips 66 Wood River Refinery alleging violations of the Illinois groundwater
standards and a third-party's hazardous waste permit. The complaint seeks as relief remediation of area
groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures;
additional spill reporting; and fines and penalties exceeding $100,000.
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. The settlement involves certain capital projects and
payment of $125,000. After the settlement was filed with the Court for final approval, the Sierra Club sought
and was granted approval to intervene in the case. The settlement and a first modification have been entered
by the Court, but the Sierra Club still seeks to reopen and challenge the settlement.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
25
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Position Held
Age*
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
60
61
57
56
55
57
60
52
59
*On February 15, 2018.
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 15, 2018. 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. On February 14, 2018, Ms. Carrig announced her decision to retire as Senior Vice President, Legal,
General Counsel and Corporate Secretary. Ms. Carrig plans to remain in her current position until her
successor is appointed.
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.
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.
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.
26
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
2017
First
Second
Third
Fourth
2016
First
Second
Third
Fourth
Stock Price
High
Low
Dividends
$
$
51.68
50.62
50.83
56.37
47.77
49.35
44.42
53.17
43.26
43.02
42.27
48.70
31.05
38.19
38.80
40.37
0.265
0.265
0.265
0.265
0.25
0.25
0.25
0.25
Closing Stock Price at December 31, 2017
Closing Stock Price at January 31, 2018
Number of Stockholders of Record at January 31, 2018*
*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency
listing.
$
$
54.89
58.46
46,680
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.
On February 1, 2018, we announced that our Board of Directors approved an increase in the quarterly dividend
to $0.285 per share, compared with the previous quarterly dividend of $0.265 per share.
27
Issuer Purchases of Equity Securities
Period
Total Number of
Shares Purchased*
Average
Price Paid
Per Share
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
Millions of Dollars
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the
Plans or Programs
October 1-31, 2017
3,496
November 1-30, 2017
3,177
December 1-31, 2017
2,874
Total fourth-quarter 2017
2,874
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
6,678,455
6,180,482
5,773,183
18,632,120
6,678,455
6,180,482
5,773,183
18,632,120
49.94
51.51
52.52
51.26
$
$
$
$
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019.
On March 29, 2017, we announced plans to double our share repurchase program to $6 billion of common
stock through 2019, with $3 billion allocated and purchased in 2017, and the remainder allocated evenly to
2018 and 2019. On February 1, 2018, we announced the acceleration of our previously stated 2018 share
repurchases from $1.5 billion to $2.0 billion, with the remaining balance to be repurchased in 2019.
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.
In addition to our previously announced share repurchase program above, we are currently planning to
purchase up to an additional $1.5 billion of our common stock through 2020. Whether we undertake these
additional repurchases is ultimately subject to numerous considerations, including Board authorization, market
conditions and other factors. See Risk Factors “Our ability to declare and pay dividends and repurchase shares
is subject to certain considerations.”
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, 2012, to December 31, 2017. The graph also compares the
cumulative total returns for the same five-year period with the S&P 500 Index and our performance peer group
consisting of BP, Chevron, ExxonMobil, Royal Dutch Shell, Total, Anadarko, Apache, Marathon Oil
Corporation, Devon and Occidental, weighted according to the respective peer’s stock market capitalization at
the beginning of each annual period. The comparison assumes $100 was invested on December 31, 2012, in
ConocoPhillips stock, the S&P 500 Index and ConocoPhillips’ peer group and assumes that all dividends were
reinvested.
28
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
2017
2016
2015
2014
2013
Sales and other operating revenues
Income (loss) from continuing operations
$
29,106
(793)
23,693
(3,559)
29,564
(4,371)
52,524
5,807
54,413
8,037
Per common share
Basic
Diluted
Income from discontinued operations
Net income (loss)
Net income (loss) attributable to
ConocoPhillips
Per common share
Basic
Diluted
Total assets
Long-term debt
Joint venture acquisition obligation—
Cash dividends declared per common share
(0.70)
(0.70)
-
(793)
(855)
(0.70)
(0.70)
73,362
17,128
(2.91)
(2.91)
-
(3,559)
(3,615)
(2.91)
(2.91)
89,772
26,186
(3.58)
(3.58)
-
(4,371)
(4,428)
4.63
4.60
1,131
6,938
6,869
6.47
6.43
1,178
9,215
9,156
(3.58)
(3.58)
97,484
23,453
5.54
5.51
116,539
22,383
7.43
7.38
118,057
21,073
1.06
1.00
2.94
2.84
2.70
Net income (loss) and net income (loss) attributable to ConocoPhillips from 2013 to 2014 includes income
from discontinued operations as a result of the sale of our interest in Kashagan, and the sales of our Algeria
and Nigeria businesses. These factors impact the comparability of this information.
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.
29
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance. It should be read in conjunction with the financial
statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains
forward-looking statements including, without limitation, statements relating to the company’s plans,
strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of
the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,”
“budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,”
“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”
and similar expressions identify forward-looking statements. The company does not undertake to update,
revise or correct any of the forward-looking information unless required to do so under the federal securities
laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the
company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page 70.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is 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 tight oil 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, 2017, we employed approximately 11,400 people
worldwide and had total assets of $73 billion. Our common stock is listed on the New York Stock Exchange
under the symbol “COP.”
Overview
The global oil market is rebalancing. Crude oil prices improved in 2017, particularly during the latter half of
the year; however, we believe prices are likely to remain cyclical in the future. In 2016, we updated our value
proposition to position the company for long-term success, given our expectations. Our value proposition
principles, namely to maintain financial strength, grow our distributions and pursue disciplined growth, remain
essentially unchanged. However, we took steps to improve our competitiveness and resilience by establishing
clear priorities for cash allocation.
In order, the cash allocation 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 to provide value to our
shareholders; and strategically invest capital to grow our cash from operations.
In 2017, we took significant actions that allowed us to make substantial progress on our stated priorities. We
believe that our commitment to our value proposition, as evidenced by the results discussed below, position the
company for success in an environment of price uncertainty and ongoing volatility.
30
Key Operating and Financial Summary
Significant items during 2017 included the following:
(cid:120) Achieved full-year production excluding Libya of 1,356 thousand barrels of oil equivalent per day
(MBOED); underlying production excluding the impact of closed and planned dispositions grew
19 percent on a production per debt-adjusted share basis and 3 percent overall.
(cid:120) Cash provided by operating activities exceeded capital expenditures by $2.5 billion, and exceeded
capital expenditures and dividends by $1.2 billion.
(cid:120) Paid down $7.6 billion of balance sheet debt, ending the year with debt of $19.7 billion.
(cid:120) Generated approximately $16 billion from asset dispositions.
(cid:120) Announced year-end proved reserves of 5.0 billion barrels of oil equivalent (BOE).
(cid:120) Repurchased $3 billion of shares; reduced ending share count by 5 percent year over year.
(cid:120) Reached settlement on Ecuador arbitration for $337 million.
Operationally, we continue to focus on safely executing our capital program and remaining attentive to our
costs. Production excluding Libya was 1,356 MBOED in 2017 compared with 1,567 MBOED in 2016. Our
underlying production, which excludes the full-year impact of closed and planned dispositions of 191 MBOED
in 2017 and 434 MBOED in 2016 and Libya, increased 32 MBOED, or 3 percent year over year. Underlying
production on a per debt-adjusted share basis grew by 19 percent compared to 2016. Production per debt-
adjusted share is calculated on an underlying production basis using ending period debt divided by ending
share price plus ending shares outstanding. We believe production per debt-adjusted share is useful to
investors as it provides a consistent view of production on a total equity basis by converting debt to equity and
allows for comparisons across peer companies.
We accomplished several strategic milestones in 2017, including progressing our efforts to optimize our
portfolio. Our asset dispositions are in line with our strategy, announced in November 2016, to focus on low
cost-of-supply projects in our portfolio that strategically fit our development plans. We generated
approximately $16 billion in total consideration from the disposition of certain noncore assets which were
directed to our stated cash priorities and general corporate purposes. For additional information on our
dispositions, see Note 4—Assets Held for Sale, Sold or Acquired in the Notes to Consolidated Financial
Statements.
In 2017, we reduced debt by $7.6 billion to $19.7 billion at year-end and repurchased 64 million shares of our
common stock totaling $3 billion. Consistent with our commitment to grow our distributions, in the first
quarter of 2017, we increased our quarterly dividend by 6 percent to $0.265 per share. We are managing our
business to optimize and deliver on our value propositions and cash priorities in a demanding business
environment.
Business Environment
After elevated levels of volatility in 2016, global market fundamentals trended towards a firmer balance in
2017. Crude oil prices improved in 2017 as a result of slower growth in global oil production, strong global oil
demand and lower global inventory levels.
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. Our strategy is to create value through price cycles by
delivering on the disciplined financial and operational priorities that underpin our value proposition.
31
Priorities
The priorities we believe will drive our success through the price cycles include:
(cid:120) Focus on financial returns. This is a core aspect of our value proposition. Our goal is to achieve
strong financial returns by controlling our costs, exercising capital discipline and continually
optimizing our portfolio.
o Control costs and expenses. Controlling operating and overhead costs, without compromising
safety and environmental stewardship, is a high priority. We monitor these costs using
various methodologies that are reported to senior management monthly, on both an absolute-
dollar basis and a per-unit basis. Managing operating and overhead costs is critical to
maintaining a competitive position in our industry, particularly in a low commodity price
environment. The ability to control our operating and overhead costs impacts our ability to
deliver strong cash from operations. In 2017, including asset disposition impacts, we reduced
our production and operating expenses by 9 percent as compared to 2016.
o Maintain capital discipline. We participate in a commodity price-driven and capital-intensive
industry, with varying lead times from when an investment decision is made to the time an
asset is operational and generates cash flow. As a result, we must invest significant capital
dollars to explore for new oil and gas fields, develop newly discovered fields, maintain
existing fields, and construct pipelines and LNG facilities. Given our view of greater price
volatility, we have shifted our capital allocation to focus on shorter cycle time, low cost-of-
supply, unconventional programs in our resource base. Our cash allocation priorities call for
the investment of sufficient capital to maintain production and pay the existing dividend.
Additional allocations of capital toward growth projects will be dependent on satisfaction of
other financial priorities. We use a disciplined approach, focused on value maximization and
cash flow expansion, to set our capital plans.
In November 2017, we announced a 2018 capital budget of $5.5 billion, including
$3.5 billion of sustaining capital and $2 billion in accretive, short-cycle unconventional
programs, future major projects and exploration activities.
o Optimize our portfolio. We continue to optimize our asset portfolio by focusing on low cost-
of-supply assets which strategically fit our development plans. In 2017, we generated
approximately $16 billion in total consideration from dispositions of certain noncore assets in
our portfolio, including our 50 percent nonoperated interest in the FCCL Partnership, as well
as the majority of our western Canada gas assets; our interests in the San Juan Basin; and our
interest in the Panhandle assets. 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.
(cid:120) Maintain financial strength. We believe financial strength is critical in a cyclical business such as
ours. In 2017, using proceeds from asset dispositions and cash flow from operations, we reduced our
debt by $7.6 billion to $19.7 billion at year-end. On a longer-term basis, in November 2017, we
announced our plan to reduce debt to $15 billion by year-end 2019, a significant acceleration from the
previously stated expectation of $20 billion in the same timeframe. We expect to retire outstanding
debt as it matures and exercise flexibility in paying down our other debt instruments.
(cid:120) Return capital to shareholders. In 2017, we paid dividends on our common stock of $1.3 billion and
repurchased $3 billion of our common stock. We believe in delivering value to our shareholders
through the price cycles. As a result, we set a priority to increase our dividend rate annually and
purchase up to approximately $3 billion of our common stock evenly from 2018 through 2019.
32
On February 1, 2018, we announced that our Board of Directors approved an increase in the quarterly
dividend to $0.285 per share, compared with the previous quarterly dividend of $0.265 per share.
Additionally, we announced the acceleration of our previously stated 2018 share repurchases from
$1.5 billion to $2.0 billion.
In addition to our previously announced share repurchase program above, we are currently planning to
purchase up to an additional $1.5 billion of our common stock through 2020. Whether we undertake
these additional repurchases is ultimately subject to numerous considerations, including Board
authorization, market conditions and other factors. See Risk Factors “Our ability to declare and pay
dividends and repurchase shares is subject to certain considerations.”
(cid:120) Maintain a relentless focus on safety and environmental stewardship. Safety and environmental
stewardship, including the operating integrity of our assets, remain our highest priorities, and we are
committed to protecting the health and safety of everyone who has a role in our operations and the
communities in which we operate. We strive to conduct our business with respect and care for both
the local and global environment and systematically manage risk to drive sustainable business growth.
Our sustainability efforts in 2017 focused on implementing our action plans for climate change,
biodiversity, water and human rights, as well as revamping public reporting to be more informative,
searchable and responsive to common questions. To demonstrate our commitment to sustainability
and environmental stewardship, on November 2017, we announced our intention to target a 5 to
15 percent reduction in our greenhouse gas emission intensity by 2030. We are committed to building
a learning organization using human performance principles as we relentlessly pursue improved
Health, Safety and Environment and operational performance.
(cid:120) Add to our proved reserve base. We primarily add to our proved reserve base in two ways:
o Successful exploration, exploitation and development of new and existing fields.
o Application of new technologies and processes to improve recovery from existing fields.
Proved reserve estimates require economic production based on historical 12-month, first-of-month,
average prices and current costs. Therefore, our proved reserves generally increase as prices rise and
decrease as prices decline. Asset dispositions in 2017 reduced our reported year-end proved reserves,
but were partly offset by increased commodity prices. In 2017, our reserve replacement, which
included a reduction of 1.9 billion BOE from dispositions, was negative 168 percent. Our organic
reserve replacement, which excludes the impact of sales and purchases, was 200 percent in 2017. In
the five years ended December 31, 2017, our reserve replacement was negative 24 percent, reflecting
the impact of asset dispositions and lower prices.
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. Additionally, as we continue cash
conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to
replace depleted reserves.
(cid:120) Apply technical capability. We leverage our knowledge and technology to create value and safely
deliver on our plans. Technical strength is part of our heritage, and we are evolving our technical
approach to optimally apply best practices. Companywide, we continue to evaluate potential solutions
to leverage knowledge of technological successes across our operations. Such innovations enable us
to economically convert additional resources to reserves, achieve greater operating efficiencies and
reduce our environmental impact.
33
(cid:120) Develop and retain a talented work force. We strive to attract, train, develop and retain individuals
with the knowledge and skills to implement our business strategy and who support our values and
ethics. To this end, we offer university internships across multiple disciplines to attract the best talent
and, as needed, recruit experienced hires to maintain a broad range of skills and experience. We
promote continued learning, development and technical training through structured development
programs designed to enhance the technical and functional skills of our employees.
Other Factors Affecting Profitability
Other significant factors that can affect our profitability include:
(cid:120)
Energy commodity prices. Our earnings and operating cash flows generally correlate with industry
price levels for crude oil and natural gas. Industry price levels are subject to factors external to the
company and over which we have no control, including but not limited to global economic health,
supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by
Organization of Petroleum Exporting Countries (OPEC), environmental laws, tax regulations,
governmental policies and weather-related disruptions. The following graph depicts the average
benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry
Hub natural gas:
Brent crude oil prices averaged $61.39 per barrel in the fourth quarter of 2017, an increase of
24 percent compared with $49.46 per barrel in the fourth quarter of 2016. Similarly, WTI crude oil
prices increased 13 percent from $49.18 per barrel in the fourth quarter of 2016 to $55.35 per barrel in
the same period of 2017. Global oil prices began to improve at the end of 2016 and continued
trending upward in response to stronger global demand and slower production growth.
Henry Hub natural gas prices averaged $2.93 per million British thermal units (MMBTU) in the fourth
quarter of 2017, a decrease of 2 percent compared with $2.98 per MMBTU in the fourth quarter of
2016. However, on an annual basis, Henry Hub natural gas prices improved 26 percent from
$2.46 per MMBTU in 2016, to $3.11 per MMBTU in 2017. The price improvement was as a result of
growth in domestic demand, increased exports and lower U.S. inventories.
Our realized natural gas liquids prices averaged $32.79 per barrel in the fourth quarter of 2017, an
increase of 50 percent compared with $21.82 per barrel in the same quarter of 2016.
Improving global crude oil prices resulted in the Western Canada Select benchmark price
experiencing a 33 percent increase, from $29.36 per barrel in 2016 to $38.92 per barrel in 2017. The
WCS benchmark price improvement, coupled with changes in costs per barrel resulting from the
34
disposition of our interest in the FCCL Partnership, caused our realized bitumen price to increase
relative to 2016. Our realized bitumen price was $22.66 per barrel in 2017, an increase of 48 percent
compared with $15.27 per barrel in the same period of 2016.
Our worldwide annual average realized price was $46.10 per barrel of oil equivalent (BOE) in the
fourth quarter of 2017, an increase of 40 percent compared with $32.93 per BOE in the fourth quarter
of 2016. Similarly, our worldwide annual average realized price was $39.19 per BOE in 2017, an
increase of 38 percent compared with $28.35 per BOE in 2016, reflecting higher average realized
prices across all commodities.
North America’s energy landscape has been transformed from resource scarcity to an abundance of
supply. 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.
(cid:120)
Impairments. As mentioned earlier, we participate in a capital-intensive industry. At times, our
properties, plants and equipment and investments become impaired when, for example, commodity
prices decline significantly for long periods of time, our reserve estimates are revised downward, or a
decision to dispose of an asset leads to a write-down to its fair value. We may also invest large
amounts of money in exploration which, if exploratory drilling proves unsuccessful, could lead to a
material impairment of leasehold values. In 2017, we recorded before-tax impairments of
$6,601 million for proved properties and $136 million for unproved properties. As we optimize our
assets in the future, it is reasonably possible we may incur future losses upon sale or impairment
charges to long-lived assets used in operations, investments in nonconsolidated entities accounted for
under the equity method, and unproved properties. For additional information on our impairments in
2017, 2016 and 2015, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.
(cid:120) Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures.
Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall
effective tax rate can vary significantly between periods based on the “mix” of before-tax earnings
within our global operations. Recent changes in the U.S. corporate income tax law, further discussed
below, additionally impacted our effective tax rate in 2017.
(cid:120) Fiscal and regulatory environment. Our operations can be affected by changing economic, regulatory
and political environments in the various countries in which we operate, including the United States.
Civil unrest or strained relationships with governments may impact our operations or investments.
These changing environments have generally negatively impacted our results of operations, and
further changes to government fiscal take could have a negative impact on future operations. Our
assets in Venezuela were expropriated in 2007. Our production operations in Libya and related oil
exports were suspended or significantly curtailed from July 2013 to October 2016 due to the closure
of the Es Sider crude oil export terminal, and they were also suspended in 2011 during Libya’s period
of civil unrest. In 2016, the United Kingdom government enacted tax legislation which reduced our
U.K. corporate tax rate by 10 percent.
On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Legislation”) was enacted, significantly
revising the U.S. corporate income tax law by, among other things, lowering the corporate income tax
rate from 35 percent to 21 percent, implementing a territorial tax system and imposing a one-time
deemed repatriation tax on untaxed accumulated foreign earnings. We recognized a provisional,
35
noncash tax benefit of $852 million, which is included as a component of our 2017 income tax
expense, primarily related to the revaluation of deferred taxes at the lower 21 percent federal statutory
rate. We did not incur nor expect to incur a tax cost related to the one-time repatriation of
accumulated foreign earnings. While we anticipate the Tax Legislation will provide a positive impact
to our U.S. operations in the future primarily because of the reduced U.S. federal statutory rate, we do
not expect to realize cash tax benefits from the Tax Legislation until we move into a U.S. tax paying
position. The ultimate impact of the Tax Legislation may differ from our current expectations, due to,
among other things, changes in interpretations and assumptions the company has made or additional
regulatory or accounting guidance that may be issued with respect to the Tax Legislation. For
additional information, see Note 18—Income Taxes, in the Notes to Consolidated Financial
Statements.
Our management carefully considers the fiscal and regulatory environment when evaluating projects
or determining the levels and locations of our activity.
Outlook
Full-year 2018 production is expected to be 1,195 to 1,235 MBOED. This results in approximately 5 percent
growth compared with full-year 2017 underlying production, which excludes the impact of closed and planned
dispositions of 191 MBOED. First-quarter 2018 production is expected to be 1,180 to 1,220 MBOED.
Production guidance for 2018 excludes Libya.
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, premiums incurred on the early retirement of debt, 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 operations, including commodity prices and production.
36
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net loss attributable to ConocoPhillips by business segment follows:
Years Ended December 31
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Net loss attributable to ConocoPhillips
2017 vs. 2016
Millions of Dollars
2017
2016
2015
$
$
1,466
(2,371)
2,564
553
(1,098)
167
(2,136)
(855)
319
(2,257)
(935)
394
209
(16)
(1,329)
(3,615)
4
(1,932)
(1,044)
409
(463)
(593)
(809)
(4,428)
Loss attributable to ConocoPhillips decreased $2,760 million in 2017. The decrease was mainly due to:
(cid:120) Higher commodity prices.
(cid:120) Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-
production rates from reserve revisions and disposition impacts.
(cid:120) Higher gains on dispositions, primarily due to a $1.6 billion after-tax gain in 2017 on the sale of
certain Canadian assets.
(cid:120) Recognition of deferred tax benefits totaling $996 million, primarily related to the disposition of
certain Canadian assets.
(cid:120) Recognition of deferred tax benefits totaling $852 million related to the Tax Legislation enacted on
(cid:120)
December 22, 2017.
Improved equity earnings, mainly due to higher realized prices, lower DD&A from asset disposition
impacts, and the absence of a 2016 deferred tax charge of $174 million resulting from the change of
the tax functional currency for APLNG to the U.S. dollar. These increases were partly offset by lower
volumes from the disposition of our interest in the FCCL Partnership.
(cid:120) Lower exploration expenses mainly due to reduced leasehold impairment expense, dry hole costs and
other exploration expenses.
(cid:120) A $337 million award from an arbitration settlement with The Republic of Ecuador.
(cid:120) Lower production and operating expenses, primarily due to asset disposition impacts.
(cid:120) Lower net interest expense, primarily due to impacts from the fair market value method of
apportioning interest expense in the United States and reduced debt.
The reduction in loss was partly offset by:
(cid:120) Higher proved property and equity investment impairments, including a combined $2.5 billion after-
tax impairment related to the sale of our interests in the San Juan Basin and the ongoing marketing of
the Barnett, as well as a $2.4 billion before- and after-tax impairment of our equity investment in
APLNG.
(cid:120) Lower volumes primarily due to asset dispositions in our Lower 48, Asia Pacific and Middle East, and
Canada segments, as well as normal field decline.
(cid:120) A $238 million after-tax charge associated with our early retirements of debt in 2017.
37
2016 vs. 2015
Loss attributable to ConocoPhillips decreased $813 million in 2016. The decrease was mainly due to:
(cid:120) Lower exploration expenses. Exploration expenses decreased mainly due to reduced leasehold
impairment expense and dry hole costs.
(cid:120) Lower proved property and equity investment impairments, including the absence of a $1.5 billion
before- and after-tax impairment of our equity investment in APLNG in 2015.
(cid:120) Lower production and operating expenses.
(cid:120) A $161 million net deferred tax benefit resulting from a reduction in the U.K. tax rate, which was
enacted in September 2016 and effective January 1, 2016.
(cid:120) The absence of a $129 million deferred tax charge from increased corporate tax rates in Canada in
2015.
The decrease in loss was partly offset by:
(cid:120) Lower commodity prices.
(cid:120) The absence of a $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in
2015.
(cid:120) Lower crude oil, natural gas liquids, and gas sales volumes.
(cid:120) Lower equity earnings, primarily driven by increased DD&A expense, as well as a 2016 deferred tax
charge of $174 million resulting from the change of the tax functional currency for APLNG to U.S.
dollar.
(cid:120) Higher interest and debt expense.
(cid:120) Lower gain on dispositions, mainly due to the absence of a $368 million after-tax gain on the
disposition of certain properties in our Lower 48 segment.
Income Statement Analysis
2017 vs. 2016
Sales and other operating revenues increased 23 percent in 2017, mainly due to higher realized prices across all
commodities, partly offset by lower sales volumes, primarily in our Lower 48, Asia Pacific and Middle East,
and Canada segments as a result of dispositions.
Equity in earnings of affiliates increased $720 million in 2017. The increase in equity earnings was primarily
due to higher realized commodity prices at QG3, APLNG and FCCL; the absence of a 2016 deferred tax
charge of $174 million resulting from a tax functional currency change; and reduced costs mainly from the
disposition of our interest in the FCCL Partnership. The increase in earnings was partly offset by lower
volumes as a result of our FCCL disposition.
Gain on dispositions increased 505 percent in 2017. The increase was primarily due to a before-tax gain of
$2.1 billion on the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority
of our western Canada gas assets. For additional information on gains on dispositions, see Note 4—Assets
Held for Sale, Sold or Acquired, in the Notes to Consolidated Financial Statements.
Other income increased 107 percent in 2017, mainly due to a $337 million before- and after-tax International
Centre for Settlement of Investment Disputes (ICSID) arbitration award from The Republic of Ecuador. The
increase was partly offset by the absence of a gain of $88 million from our receipt of mineral properties and
active leases from the Greater Northern Iron Ore Properties Trust and a $76 million before-tax damage claim
settlement, both in our Lower 48 segment in 2016.
Purchased commodities increased 25 percent in 2017, mainly due to higher commodity prices and increased
activity.
38
Selling, general and administrative (SG&A) expenses decreased 22 percent in 2017, primarily due to reduced
restructuring expenses, lower headcount and reduced activity.
Exploration expenses decreased 51 percent in 2017, 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 2016 before-tax charges of
$203 million for our Gibson and Tiber leaseholds. The expense was further reduced by the absence of before-
tax charges of $95 million for our Melmar leasehold and $79 million for various Gulf of Mexico leases after
completion of marketing efforts. The reduction was partly offset by a before-tax charge of $51 million for
Shenandoah in deepwater Gulf of Mexico and a before-tax charge of $38 million for certain mineral assets in
our Lower 48 segment, both in 2017.
Dry hole costs were reduced primarily due to the absence of 2016 before-tax charges in deepwater Gulf of
Mexico of $249 million for our Gibson and Tiber wells, and $128 million for our Melmar well. The absence
of a $256 million before-tax charge in 2016 for two dry holes in Nova Scotia further reduced costs. The
reduction in dry hole costs was partly offset by 2017 before-tax charges of $288 million for multiple wells in
Shenandoah, including wells previously suspended, and $63 million for several wells in the Powder River
Basin.
Other exploration expenses were reduced mainly due to the absence of a $146 million before-tax expense in
2016 related to the cancellation of our final Gulf of Mexico deepwater drillship contract, as well as lower rig
stacking costs in Angola. The decrease in expense was partly offset by a $43 million net before-tax charge in
2017 for the settlement of our drilling rig contract in Angola.
For additional information on leasehold impairments and other exploration expenses, see Note 7—Suspended
Wells and Other Exploration Expenses, and Note 8—Impairments, in the Notes to Consolidated Financial
Statements.
DD&A decreased 24 percent in 2017, mainly due to lower unit-of-production rates from reserve revisions and
disposition impacts in our Canada and Lower 48 segments.
Impairments increased $6,462 million in 2017. For additional information, see Note 8—Impairments, in the
Notes to Consolidated Financial Statements.
Interest and debt expense decreased 12 percent in 2017, primarily due to impacts from the fair market value
method of apportioning interest expense in the United States and lower interest on debt.
Other expense included before-tax charges of $302 million in 2017 for premiums on early debt retirements.
See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax benefit and effective tax rate.
2016 vs. 2015
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 QG3.
39
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 noncore 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 noncore
assets in the Lower 48. For additional information on gains on dispositions, see Note 4—Assets Held for Sale,
Sold or Acquired, in the Notes to Consolidated Financial Statements.
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 noncore assets, as well as favorable foreign currency impacts.
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 7—Suspended
Wells and Other Exploration Expenses, and Note 8—Impairments, in the Notes to Consolidated Financial
Statements.
Impairments decreased 94 percent in 2016. For additional information, see Note 8—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.
40
Interest and debt expense increased 35 percent in 2016, primarily due to lower capitalized interest on projects
and increased debt.
See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax benefit and effective tax rate.
Summary Operating Statistics
Average Net Production
Crude oil (MBD)*
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)**
2017
2016
2015
599
111
122
3,270
598
145
183
3,857
605
156
151
4,060
Total Production (MBOED)***
1,377
1,569
1,589
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
Dollars Per Unit
51.96
25.22
22.66
4.07
40.86
16.68
15.27
3.00
48.26
17.79
18.72
3.96
Millions of Dollars
372
136
430
938
731
466
718
1,915
1,127
1,924
1,141
4,192
$
$
$
*Thousands of barrels per day.
**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.
***Thousands of barrels of oil equivalent per day.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on
a worldwide basis. At December 31, 2017, our operations were producing in the United States, Norway, the
United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.
Total production, including Libya, of 1,377 MBOED decreased 12 percent in 2017 compared with 2016. The
decrease in total average production primarily resulted from noncore asset dispositions, including our Canada
and San Juan transactions in 2017 and the sale of our interest in the Block B production sharing contract (PSC)
in Indonesia in 2016, and normal field decline. The decrease in production was partly offset by production
from major developments, including tight oil plays in the Lower 48; Malikai and the Kebabangan gas field in
Malaysia; Surmont in Canada; and APLNG in Australia. Improved drilling and well performance in Alaska,
Norway and China also partly offset the decrease in production. Excluding Libya, our 2017 production was
1,356 MBOED. Adjusted for the impact of closed and planned dispositions of 191 MBOED in 2017 and
434 MBOED in 2016 and Libya, our underlying production increased 32 MBOED, or 3 percent, compared
with 2016.
In 2016, total production, including Libya, of 1,569 MBOED decreased 1 percent 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 noncore assets in the Lower 48, western Canada and the
41
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.
Alaska
Net Income Attributable to ConocoPhillips (millions of dollars) $
1,466
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas (per thousand cubic feet)
2016
319
163
12
25
179
2015
4
158
13
42
178
167
14
7
182
$
53.33
2.72
41.93
5.22
51.61
4.33
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids,
natural gas and LNG. In 2017, Alaska contributed 22 percent of our worldwide liquids production and less
than 1 percent of our natural gas production.
2017 vs. 2016
Alaska reported earnings of $1,466 million in 2017, compared with earnings of $319 million in 2016. The
increase in earnings was mainly due to an $892 million tax benefit from the revaluation of allocated U.S.
deferred taxes at a lower federal statutory rate, in accordance with the newly enacted Tax Legislation.
Earnings were additionally improved due to higher crude oil prices in 2017. The earnings increase was partly
offset by a $110 million after-tax impairment charge for the associated properties, plants and equipment of our
small interest in the Point Thomson unit.
Average production increased 2 percent in 2017 compared with 2016, as the impact of normal field decline
was more than offset by well performance in the Western North Slope, Greater Prudhoe and Greater Kuparuk
areas and lower unplanned downtime.
2016 vs. 2015
Alaska reported earnings of $319 million in 2016, compared with earnings of $4 million in 2015. The increase
in earnings was mainly due to:
(cid:120) Lower exploration expenses, primarily due to the absence of the 2015 impairment charge for our
Chukchi Sea leasehold and capitalized interest. For additional information on our impairments, see
Note 8—Impairments, in the Notes to Consolidated Financial Statements.
(cid:120) Reduced production and operating expense, mainly from lower maintenance costs and general and
administrative expenses.
(cid:120) Enhanced oil recovery tax credits.
42
(cid:120) Higher crude oil sales volumes, partly offset by the absence of LNG sales volumes.
(cid:120) A $57 million after-tax impact for the recognition of state deferred tax assets.
(cid:120) A $36 million after-tax gain on the sale of our interest in the Alaska Beluga River Unit natural gas
field.
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.
Acquisition
In January 2018, we entered into an agreement to acquire certain oil and gas assets in Alaska for $400 million,
subject to customary adjustments. The acquisition is subject to regulatory approval. We will have a
100 percent interest in approximately 1.2 million acres of exploration and development lands, including the
Willow Discovery.
Lower 48
Net Loss Attributable to ConocoPhillips (millions of dollars)
$
(2,371)
(2,257)
(1,932)
2017
2016
2015
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Natural gas (per thousand cubic feet)
180
69
898
399
195
88
1,219
206
94
1,472
486
545
$
47.36
22.20
2.73
37.49
14.34
2.20
42.62
14.01
2.43
The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in
the Gulf of Mexico. During 2017, the Lower 48 contributed 30 percent of our worldwide liquids production
and 27 percent of our natural gas production.
2017 vs. 2016
Lower 48 reported a loss of $2,371 million after-tax in 2017, compared with a loss of $2,257 million after-tax
in 2016. The increase in loss was primarily due to proved property impairments in 2017, totaling $2.5 billion
after-tax, for our interests in the San Juan Basin and the Barnett which were written down to fair value less
costs to sell. Lower natural gas, crude oil and natural gas liquids sales volumes from asset dispositions and
normal field decline further increased losses during the year.
43
The increase in losses was partly offset by:
(cid:120) Lower DD&A expense, mainly resulting from a lower unit-of-production rate from reserve revisions,
disposition impacts and lower volumes.
(cid:120) A $689 million tax benefit, primarily related to the revaluation of allocated U.S. deferred taxes at a
lower federal statutory rate, in accordance with the newly enacted Tax Legislation.
(cid:120) Higher realized crude oil, natural gas liquids and natural gas prices.
(cid:120) Lower exploration expenses mainly due to:
o Lower leasehold impairment expense, primarily the absence of 2016 after-tax charges of
$132 million for our Gibson and Tiber leaseholds; $62 million for our Melmar leasehold and
$52 million for various Gulf of Mexico leases after completion of marketing efforts. The
reduction was partly offset by an after-tax charge of $33 million for Shenandoah in deepwater
Gulf of Mexico and an after-tax charge of $24 million for certain mineral assets, both in 2017.
o Lower other exploration expenses, mainly due to the absence of a $95 million after-tax
expense in 2016 related to the cancellation of our final Gulf of Mexico deepwater drillship
contract.
o Lower dry hole costs primarily due to the absence of 2016 after-tax charges in deepwater
Gulf of Mexico of $162 million for our Gibson and Tiber wells, and $83 million for our
Melmar well, partly offset by 2017 after-tax charges of $187 million for multiple wells in
Shenandoah and $41 million for several wells in the Powder River Basin.
In 2017, our average realized crude oil price of $47.36 per barrel was 7 percent less than WTI of $50.90 per
barrel. The differential is driven primarily by local market dynamics in the Gulf Coast and Bakken.
Total average production decreased 18 percent in 2017 compared with 2016. The decrease was mainly
attributable to normal field decline and the disposition of our interests in the San Juan Basin, partly offset by
new production, primarily from Eagle Ford and Bakken.
Asset Disposition
On July 31, 2017, we completed the sale of our interests in the San Juan Basin for total proceeds comprised of
$2.5 billion in cash after customary adjustments and a contingent payment of up to $300 million. The six-year
contingent payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly
U.S. Henry Hub price is at or above $3.20 per million British thermal units.
On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash
after customary adjustments.
For additional information on our asset sales in the Lower 48, see Note 4—Assets Held for Sale, Sold or
Acquired, in the Notes to Consolidated Financial Statements.
2016 vs. 2015
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:
(cid:120) The absence of a $368 million after-tax gain on the disposition of certain properties in South Texas,
East Texas and North Louisiana.
(cid:120) Lower crude oil and natural gas prices.
(cid:120) Lower sales volumes across all commodities due to dispositions and field decline.
(cid:120) Higher proved property impairments, including a $49 million after-tax impairment associated with
changes to development plans for Eagle Ford infrastructure.
44
The increase in losses was partly offset by:
(cid:120) Lower production and operating expenses, mainly due to reduced activity and cost efficiencies.
(cid:120) Lower exploration expenses, mainly due to:
o Reduced other exploration costs, mainly due to the absence of a $216 million after-tax charge
related to the termination of our Gulf of Mexico deepwater drillship contract with Ensco in
2015, partly offset by 2016 rig cancellation and related third party costs of $95 million after-
tax for our final Gulf of Mexico deepwater drillship contract.
o Lower general and administrative, and geological and geophysical expenses.
o Lower leasehold impairment expense, including the absence of 2015 after-tax charges of
$154 million for certain leases in the Gulf of Mexico and $100 million for various blocks in
the Gila Prospect. The decrease in leasehold impairment was partly offset by 2016 after-tax
charges of $132 million for our Gibson and Tiber leaseholds and $62 million for the Melmar
Prospect, all in the Gulf of Mexico.
o Lower exploration expenses were partly offset by slightly increased dry hole costs in 2016,
including after-tax charges in deepwater Gulf of Mexico of $162 million for our Gibson and
Tiber wells and $83 million associated with our Melmar well. Dry hole costs in 2016 were
partly offset by the absence of a $111 million after-tax charge in 2015 associated with two
wells in the Gila Prospect in the deepwater Gulf of Mexico.
(cid:120) An $88 million gain associated with our receipt of Greater Northern Iron Ore Properties Trust assets
in the fourth quarter of 2016.
(cid:120) A $48 million after-tax benefit from a damage claim settlement.
(cid:120) A $38 million after-tax gain from the disposition of noncore assets and lease exchanges.
(cid:120) Lower DD&A, mainly due to 2016 reserve additions and reduced volumes, partly offset by
price-related reserve revisions.
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 noncore 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.
45
Canada
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
2,564
(935)
(1,044)
2017
2016
2015
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Bitumen (MBD)
Consolidated operations
Equity affiliates
Total bitumen
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (dollars per barrel)
Consolidated operations
Equity affiliates
Total bitumen
Natural gas (per thousand cubic feet)
3
9
59
63
122
187
165
43.69
21.51
21.43
23.83
22.66
1.93
7
23
35
148
183
524
300
35.25
14.82
12.91
15.80
15.27
1.49
12
26
13
138
151
715
308
39.52
17.02
20.13
18.58
18.72
1.91
$
Our Canadian operations mainly consist of an oil sands development in the Athabasca region of northeastern
Alberta and a liquids-rich unconventional play in western Canada. In 2017, Canada contributed 16 percent of
our worldwide liquids production and 6 percent of our worldwide natural gas production.
2017 vs. 2016
Canada operations reported earnings of $2,564 million in 2017, an increase of $3,499 million compared with
2016. The earnings increase was mainly due to an after-tax gain of $1.6 billion on the sale of certain Canadian
assets, further discussed below, as well as the recognition of $996 million in deferred tax benefits related to the
capital gains component of our disposition and the recognition of previously unrealizable Canadian tax basis.
In addition to the items discussed above, earnings were further increased due to:
(cid:120) Lower DD&A, mainly from disposition impacts.
(cid:120) Lower dry hole costs, mainly due to the absence of 2016 combined after-tax charges in offshore
Nova Scotia of $187 million for our Cheshire and Monterey Jack wells.
(cid:120) Higher realized prices across all commodities.
(cid:120) A $114 million tax benefit related to our prior decision to exit Nova Scotia deepwater exploration.
(cid:120) Lower production and operating expenses.
(cid:120)
Improved equity earnings, as improved prices and reduced DD&A more than offset the volume loss
from our Canada disposition.
46
The earnings increase was partly offset by additional volume reductions from the disposition of our western
Canada gas assets.
Total average production decreased 45 percent in 2017 compared with 2016. The production decrease was
primarily due to the Canada disposition, partly offset by production ramp-up at Surmont.
Asset Disposition
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction
was $11.0 billion in cash after customary adjustments, 208 million Cenovus Energy common shares and a
five-year uncapped contingent payment. The contingent payment, calculated and paid on a quarterly basis, is
$6 million Canadian dollars (CAD) for every $1 CAD by which the Western Canada Select (WCS) quarterly
average crude price exceeds $52 CAD per barrel. See Note 4—Assets Held for Sale, Sold or Acquired and
Note 6—Investment in Cenovus Energy, in the Notes to Consolidated Financial Statements, for additional
information regarding our Canada disposition.
2016 vs. 2015
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:
(cid:120) The absence of a $136 million impact of a 2 percent increase in Alberta corporate tax rates on deferred
taxes in 2015.
(cid:120) Lower production and operating expenses, mainly due to reduced headcount and the disposition of
noncore assets in western Canada.
(cid:120) Lower exploration expenses, mainly due to:
o Reduced leasehold impairment expense, including the absence of an impairment charge for
undeveloped leasehold in the Duvernay, Thornbury, Saleski and Crow Lake areas. The
reduction in leasehold impairment expense was partly offset by a $23 million after-tax charge
in the fourth quarter of 2016 primarily due to decisions to discontinue further testing on
undeveloped leaseholds.
o Lower general and administrative, and geological and geophysical expenses.
o Lower dry hole costs, mainly due to the absence of 2015 charges associated with our Horn
River, Northwest Territories, Thornbury and Saleski properties, partly offset by dry hole costs
in 2016, including total after-tax charges in offshore Nova Scotia of $187 million for our
Cheshire and Monterey Jack wells.
(cid:120) Higher gains on dispositions, including the absence of a $103 million net after-tax loss on the
disposition of noncore assets in western Canada in 2015.
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 noncore assets in western Canada and normal field decline. The production decrease was partly
offset by strong well performance in western Canada, Surmont and FCCL.
47
Europe and North Africa
Net Income Attributable to ConocoPhillips (millions of dollars) $
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (dollars per barrel)
Natural gas liquids (per barrel)
Natural gas (per thousand cubic feet)
2017
553
142
8
484
230
2016
394
122
7
460
205
2015
409
120
7
476
207
$
54.21
34.07
5.70
43.66
22.62
4.71
52.75
27.56
7.14
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 2017, our Europe and North Africa operations
contributed 18 percent of our worldwide liquids production and 15 percent of our natural gas production.
2017 vs. 2016
Earnings for Europe and North Africa operations of $553 million increased 40 percent in 2017. The increase
in earnings was primarily due to higher realized crude oil, natural gas and natural gas liquids prices. Earnings
were additionally improved by lower DD&A, mainly due to reserve revisions; a $60 million tax benefit from
the revaluation of allocated U.S. deferred taxes at a lower U.S. federal statutory rate, in accordance with the
newly enacted Tax Legislation; and a $41 million tax benefit in Norway.
The increase in earnings was partly offset by the absence of a 2016 net deferred tax benefit of $161 million
resulting from a change in the U.K. tax rate and a lower credit to impairment in 2017, compared to 2016,
reflecting the annual updates to asset retirement obligations (ARO) on fields at or nearing the end of life which
were impaired in prior years. The earnings improvement was further reduced by a net deferred tax charge of
$65 million in the U.K. resulting from updated assumptions regarding applicable tax rates.
Average production increased 12 percent in 2017, compared with 2016. The increase was mainly due to the
resumption and ramp-up of production in Libya; improved drilling and well performance in Norway; new
production from the Greater Britannia Area and Norway; and higher Norway gas offtake, partly offset by
normal field decline.
2016 vs. 2015
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).
48
The decrease in earnings was partly offset by:
(cid:120) Lower property impairments, including the absence of 2015 after-tax charges of $317 million in the
U.K. due to lower crude oil and natural gas prices, and a $180 million credit to impairment in 2016
due to decreased ARO estimates on fields at or nearing the end of life which were impaired in prior
years. The reduction in property impairments was partly offset by a $59 million after-tax charge
associated with our Calder Field and Rivers terminal in the U.K. For additional information on our
impairments, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.
(cid:120) Lower DD&A expense in the U.K. driven by reduced rate, as a result of completed depreciation on the
Brodgar H3 tie-back well in 2015, and lower volumes.
(cid:120) A $161 million net deferred tax benefit resulting from a reduction in the U.K. tax rate, which was
enacted in September 2016 and effective January 1, 2016.
(cid:120) Reduced operating expenses across the segment.
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.
49
Asia Pacific and Middle East
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(1,098)
209
(463)
2017
2016
2015
Average Net Production
Crude oil (MBD)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (MBD)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (MMCFD)
Consolidated operations
Equity affiliates
Total natural gas
93
14
107
4
7
11
97
14
111
7
8
15
91
14
105
9
7
16
687
1,007
1,694
730
899
1,629
717
638
1,355
Total Production (MBOED)
401
399
347
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (dollars per barrel)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (dollars per thousand cubic feet)
Consolidated operations
Equity affiliates
Total natural gas
$
54.38
54.76
54.43
41.37
38.74
39.75
4.98
4.27
4.55
42.23
44.11
42.47
29.00
31.13
30.11
4.31
2.97
3.57
49.70
53.12
50.16
37.78
35.79
36.88
6.23
4.83
5.58
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 2017, Asia Pacific and Middle East contributed
14 percent of our worldwide liquids production and 52 percent of our natural gas production.
2017 vs. 2016
Asia Pacific and Middle East reported a loss of $1,098 million in 2017, compared with earnings of $209 million
in 2016. The increase in loss was mainly due to a $2,384 million before- and after-tax charge for the impairment
of our APLNG investment in 2017. For additional information on our APLNG impairment, see the “APLNG”
section of Note 5—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements. Additionally, lower sales volumes in Indonesia, Australia and China further increased losses.
50
The increase in losses was partly offset by higher equity earnings, mainly as a result of higher commodity prices,
increased sales volumes at APLNG and the absence of a 2016 deferred tax charge of $174 million resulting from
the change of our APLNG tax functional currency. Higher realized crude oil and natural gas prices on non-
equity volumes further reduced the loss.
Average production was essentially flat in 2017.
2016 vs. 2015
Asia Pacific and Middle East reported earnings of $209 million in 2016, compared with a loss of $463 million in
2015. The earnings increase was mainly due to:
(cid:120) The absence of a $1,502 million before- and after-tax charge for the impairment of our APLNG
investment in 2015. For additional information on our APLNG impairment, see the “APLNG” section
of Note 5—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements.
(cid:120) Higher LNG sales volumes.
(cid:120) Lower production taxes.
(cid:120) Reduced feedstock costs at Darwin LNG.
(cid:120) Lower operating expenses, mainly due to lower general and administrative spend, maintenance costs
and transportation expenses across the segment.
(cid:120) Lower exploration expenses, mainly due to lower dry hole costs, as well as the absence of a
$41 million after-tax charge in 2015 for the impairment of our relinquished Palangkaraya PSC, and
reduced exploration general and administrative expense.
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.
Other International
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
167
(16)
(593)
2017
2016
2015
Average Net Production
Crude oil (MBD)
Equity affiliates
Total Production (MBOED)
Average Sales Prices
Crude oil (dollars per barrel)
Equity affiliates
-
-
-
-
-
4
4
-
37.21
The Other International segment includes exploration activities in Colombia and Chile.
51
2017 vs. 2016
Other International operations reported earnings of $167 million in 2017, compared with a loss of $16 million
in 2016. The increase in earnings was primarily due to a $320 million before- and after-tax ICSID award from
an arbitration with The Republic of Ecuador. Earnings were additionally increased due to lower rig stacking
costs in Angola. The increase in earnings was partly offset by the absence of a $138 million gain in 2016 on
the disposition of ConocoPhillips Senegal B.V., the entity that held our interest in three exploration blocks
offshore Senegal, and a $45 million tax charge from the revaluation of allocated U.S. deferred taxes at a lower
U.S. federal statutory rate, in accordance with the newly enacted Tax Legislation.
2016 vs. 2015
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 2016 disposition of ConocoPhillips Senegal B.V., the entity that
held our interest in three exploration blocks offshore Senegal.
Corporate and Other
Net Loss Attributable to ConocoPhillips
Net interest
Corporate general and administrative expenses
Technology
Other
2017 vs. 2016
Millions of Dollars
2017
2016
$
$
(739)
(284)
20
(1,133)
(2,136)
(980)
(289)
50
(110)
(1,329)
2015
(518)
(246)
122
(167)
(809)
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest decreased 25 percent in 2017 compared with 2016, primarily due to impacts from the fair market value
method of apportioning interest expense in the United States and lower interest as a result of reduced debt.
Higher interest income further drove the decrease in net interest, which was partly offset by lower capitalized
interest on projects.
Corporate general and administrative expenses which include pension settlement expenses and compensation
program costs was essentially flat in 2017.
Technology includes our investment in new technologies or businesses, as well as licensing revenues received.
Activities are focused on tight oil reservoirs, LNG, oil sands and other production operations. Earnings from
Technology were $20 million in 2017, compared with $50 million in 2016. The decrease in earnings primarily
resulted from lower licensing revenues, partly offset by reduced technology program spend.
The category “Other” includes certain foreign currency transaction gains and losses, environmental costs
associated with sites no longer in operation, other costs not directly associated with an operating segment and
premiums incurred on the early retirement of debt. “Other” expenses increased $1,023 million in 2017, mainly
due to an $813 million tax charge from the revaluation of deferred taxes at a lower federal statutory rate, in
accordance with the newly enacted Tax Legislation and premiums on our early retirement of debt.
52
2016 vs. 2015
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.
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.
“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.
53
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Net cash provided by operating activities
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.
Millions of Dollars
Except as Indicated
2017
2016
2015
$
7,077
6,325
2,575
19,703
30,801
39 %
5 %
4,403
3,610
1,089
27,275
35,226
44
9
7,572
2,368
1,427
24,880
40,082
38
7
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including
cash generated from operating activities, proceeds from asset sales, our commercial paper and credit facility
programs and our shelf registration statement. In 2017, the primary uses of our available cash were
$7,876 million to reduce debt; $4,591 million to support our ongoing capital expenditures and investments
program; $1,305 million to pay dividends on our common stock; $1,790 million net purchases of short-term
investments; $3,000 million to repurchase our common stock; and a $600 million contribution to our domestic
qualified pension plan. During 2017, cash and cash equivalents increased by $2,715 million to $6,325 million.
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, share repurchases, dividend
payments and required debt payments.
Significant Sources of Capital
Operating Activities
During 2017, cash provided by operating activities was $7,077 million, a 61 percent increase from 2016. The
increase was primarily due to higher prices across all commodities.
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
2017 production averaged 1,377 MBOED. Full-year 2018 production is expected to be 1,195 to
1,235 MBOED. This results in approximately 5 percent growth compared with full-year 2017 underlying
production, which excludes the impact of closed and planned dispositions of 191 MBOED. Production
guidance for 2018 excludes Libya. Future production is subject to numerous uncertainties, including, among
others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the
effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of
fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major
turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through
exploratory success and their timely and cost-effective development. While we actively manage these factors,
production levels can cause variability in cash flows, although generally this variability has not been as
significant as that caused by commodity prices.
54
To maintain or grow our production volumes on an ongoing basis, we must continue to add to our proved
reserve base. Our total reserve replacement in 2017 was negative 168 percent. Our organic reserve
replacement, which excludes the impact of sales and purchases, was 200 percent in 2017. Over the five-year
period ended December 31, 2017, our reserve replacement was a negative 24 percent (including 3 percent from
consolidated operations) reflecting the impact of asset dispositions and lower prices. 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 2018 capital budget, see the “2018 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 2017, revisions increased
reserves, while in 2016 and 2015, revisions decreased reserves. It is not possible to reliably predict how
revisions will impact reserve quantities in the future.
Investing Activities
Proceeds from asset sales in 2017 were $13.9 billion. We completed the sale of our 50 percent nonoperated
interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.
Consideration for the transaction included $11.0 billion in cash after customary adjustments and 208 million
Cenovus Energy common shares. We completed the sale of our interests in the San Juan Basin to an affiliate
of Hilcorp Energy Company. Total proceeds for the sale was $2.5 billion in cash after customary adjustments.
We also completed the sale of our interest in the Panhandle assets for $178 million in cash after customary
adjustments.
Proceeds from asset dispositions 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.
For additional information on our dispositions and investment in Cenovus common shares, see Note 4—Assets
Held for Sale, Sold or Acquired and Note 6—Investment in Cenovus Energy, in the Notes to Consolidated
Financial Statements, and the Results of Operations section within Management’s Discussion and Analysis.
Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.75 billion, expiring in June 2019. 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.
We have two commercial paper programs. The ConocoPhillips $6.25 billion commercial paper program is
available to fund short-term working capital needs. We also have the ConocoPhillips Qatar Funding Ltd.
$500 million commercial paper program, which is used to fund commitments relating to QG3. Commercial
paper maturities are generally limited to 90 days. We had no commercial paper outstanding at December 31,
2017 or 2016, under either the ConocoPhillips or the ConocoPhillips Qatar Funding Ltd. commercial paper
55
program. We had no direct borrowings or letters of credit issued under the revolving credit facility. 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, 2017.
In the first quarter of 2017, Fitch and Standard & Poor’s reflected an improvement in their outlook for our debt
from “negative” to “stable” and affirmed our long-term debt rating at “A-.” In January 2018, Fitch further
improved their outlook for our debt from “stable” to “positive.” After improving their outlook for our debt
from “negative” to “positive” in the first quarter of 2017, Moody’s Investor Services upgraded our long-term
debt rating from “Baa2” to “Baa1” with a stable outlook in the third quarter of 2017 in response to our debt
reduction. We do not have any ratings triggers on any of our corporate debt that would cause an automatic
default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our
credit rating were downgraded, it could increase the cost of corporate debt available to us and restrict our
access to the commercial paper markets. 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, 2017 and 2016, we had direct bank letters of credit of $338 million
and $304 million, respectively, which secured performance obligations related to various purchase
commitments incident to the ordinary conduct of business. In the event of 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 11—Guarantees, in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
56
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures” section.
Our debt balance at December 31, 2017, was $19.7 billion, a decrease of $7.6 billion from the balance at
December 31, 2016.
In 2017, two notes totaling $1,001 million were paid at maturity, including the $1.0 billion 1.05% Notes due
2017. Also in 2017, we prepaid the $1,450 million term loan facility due in 2019. We also redeemed a total
$5.0 billion of debt, described below, incurring $301 million in premiums above book value, which are
reported in the “Other expense” line on our consolidated income statement.
(cid:120) 6.65% Debentures due 2018 with principal of $297 million.
(cid:120) 5.20% Notes due 2018 with principal of $500 million.
(cid:120) 1.5% Notes due 2018 with principal of $750 million.
(cid:120) 5.75% Notes due 2019 with principal of $2.25 billion.
(cid:120) 6.00% Notes due 2020 with principal of $1.0 billion.
(cid:120) 4.20% Notes due 2021 with principal of $1.25 billion (partial redemption of $250 million).
In the fourth quarter of 2017, we gave notice to redeem the following debt instruments totaling $2.25 billion.
(cid:120) 2.2% Notes due 2020 with principal of $500 million.
(cid:120) 4.20% Notes due 2021 with remaining principal of $1.0 billion.
(cid:120) 2.875% Notes due 2021 with principal of $750 million.
The prepayments occurred on January 22, 2018, and we incurred premiums above book value of $75 million.
On a longer-term basis our debt target is $15 billion by year-end 2019. In the future, we may redeem other
debt instruments or purchase debt instruments in the open market or otherwise, as we seek to achieve this
target. Any such redemptions or purchases would be subject to market conditions and other factors, and may
be conducted or discontinued at any time without prior notice. For more information on Debt, see Note 10—
Debt, in the Notes to Consolidated Financial Statements.
On January 31, 2017, we announced a 6 percent increase in the quarterly dividend to $0.265 per share. The
dividend was paid on March 1, 2017, to stockholders of record at the close of business on February 14, 2017.
On May 5, 2017, we announced a quarterly dividend of $0.265 per share. The dividend was paid on June 1,
2017, to stockholders of record at the close of business on May 15, 2017. On July 12, 2017, we announced a
quarterly dividend of $0.265 per share. The dividend was paid on September 1, 2017, to stockholders of
record at the close of business on July 24, 2017. On October 6, 2017, we announced a quarterly dividend of
$0.265 per share which was paid on December 1, 2017, to stockholders of record at the close of business on
October 16, 2017. Additionally, on February 1, 2018, we announced an increase in the quarterly dividend to
$0.285 per share, compared with the previous quarterly dividend of $0.265 per share. The dividend is payable
on March 1, 2018, to stockholders of record at the close of business on February 12, 2018.
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019.
On March 29, 2017, we announced plans to double our share repurchase program to $6 billion of common
stock through 2019, with $3 billion allocated and purchased in 2017, and the remainder allocated evenly to
2018 and 2019. On February 1, 2018, we announced the acceleration of our previously stated 2018 share
repurchases from $1.5 billion to $2.0 billion, with the remaining balance to be repurchased in 2019. Since our
share repurchase program began in November 2016, we have repurchased 66 million shares at a cost of
$3.1 billion through December 31, 2017.
In addition to our previously announced share repurchase program above, we are currently planning to
purchase up to an additional $1.5 billion of our common stock through 2020. Whether we undertake these
57
additional repurchases is ultimately subject to numerous considerations, including Board authorization, market
conditions and other factors. See Risk Factors “Our ability to declare and pay dividends and repurchase shares
is subject to certain considerations.”
During the third quarter of 2017, we made a $600 million contribution to our domestic qualified pension plan,
which is included in the “Other” line in the “Cash Flows From Operating Activities” section of our
consolidated statement of cash flows. This additional contribution significantly lowers our domestic pension
deficit which will reduce future premiums charged by the Pension Benefit Guaranty Corporation. It also
mitigates the need for contributions in future quarters.
Contractual Obligations
The table below summarizes our aggregate contractual fixed and variable obligations as of December 31, 2017:
Millions of Dollars
Payments Due by Period
Total
18,929
774
19,703
13,884
1,548
10,102
1,312
7,798
180
51
54,578
$
$
Up to 1
Year
2,508
67
2,575
955
278
4,210
210
251
25
51
8,555
Years
2–3
63
147
210
1,881
628
1,833
491
687
36
(h)
5,766
Years
4–5
After
5 Years
1,706
132
1,838
1,834
433
945
611
575
29
(h)
6,265
14,652
428
15,080
9,214
209
3,114
-
6,285
90
(h)
33,992
Debt obligations (a)
Capital lease obligations (b)
Total debt
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
(a)
Includes $252 million of net unamortized premiums, discounts and debt issuance costs. See Note 10—
Debt, in the Notes to Consolidated Financial Statements, for additional information.
(b) Capital lease obligations are presented on a discounted basis.
(c) Operating lease obligations are presented on an undiscounted basis.
(d) Represents any agreement to purchase goods or services that is enforceable and legally binding and that
specifies all significant terms, presented on an undiscounted basis. Does not include purchase
commitments for jointly owned fields and facilities where we are not the operator.
The majority of the purchase obligations are market-based contracts related to our commodity business.
Product purchase commitments with third parties totaled $3,487 million.
Purchase obligations of $5,443 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.
58
(e) Represents contributions to qualified and nonqualified pension and postretirement benefit plans for the
years 2018 through 2022. For additional information related to expected benefit payments subsequent to
2022, see Note 17—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.
(f) Represents estimated discounted costs to retire and remove long-lived assets at the end of their
operations.
(g) Represents estimated costs for accrued environmental expenditures presented on a discounted basis for
costs acquired in various business combinations and an undiscounted basis for all other accrued
environmental costs.
(h) Excludes unrecognized tax benefits of $831 million because the ultimate disposition and timing of any
payments to be made with regard to such amounts are not reasonably estimable. Although unrecognized
tax benefits are not a contractual obligation, they are presented in this table because they represent
potential demands on our liquidity.
Capital Expenditures
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Capital Program
Millions of Dollars
2017
2016
2015
$
$
815
2,136
202
872
482
21
63
4,591
883
1,262
698
1,020
838
104
64
4,869
1,352
3,765
1,255
1,573
1,812
173
120
10,050
Our capital expenditures and investments for the three-year period ended December 31, 2017, totaled
$19.5 billion. The 2017 expenditures supported key exploration and developments, primarily:
(cid:120) Oil and natural gas development and exploration and appraisal activities in the Lower 48, including
Eagle Ford, Bakken, the Permian Basin, the Niobrara in the Denver-Julesburg Basin and several
emerging plays.
(cid:120) Alaska activities related to development in the Western North Slope, Greater Kuparuk Area, and the
Greater Prudhoe Area.
(cid:120) Development activities in Europe, including the Greater Ekofisk Area, Clair Ridge, Aasta Hansteen,
and Heidrun.
(cid:120) Continued oil sands development and appraisal activities in liquids-rich plays in Canada.
(cid:120) Continued development in Malaysia, Indonesia, China, and Australia; appraisal activity in Australia
and exploration activity in Malaysia.
2018 CAPITAL BUDGET
In November 2017, we announced a 2018 capital budget of $5.5 billion, including $3.5 billion of sustaining
capital and $2 billion in accretive, short-cycle unconventional programs, future major projects and exploration
activities.
59
We are planning to allocate approximately:
(cid:120) 51 percent of our 2018 capital expenditures budget to development drilling programs. These funds
will focus predominantly on the Lower 48 unconventionals including the Eagle Ford, Bakken and
Permian, as well as development drilling in Australia/Timor-Leste, Norway and Alaska.
(cid:120) 18 percent of our 2018 capital expenditures budget to maintain base production and corporate
expenditures.
(cid:120) 17 percent of our 2018 capital expenditures budget to major projects. These funds will focus on major
projects in China, Alaska, Europe and Malaysia.
(cid:120) 8 percent of our 2018 capital expenditures budget to new exploration activity, primarily in Alaska and
the Lower 48.
(cid:120) 6 percent of our 2018 capital expenditures budget to development appraisal, including the Lower 48,
Canada and Alaska.
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 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty
and severance tax payments, gas measurement and valuation methods, contract disputes, environmental
damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged
royalty 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 18—Income Taxes, in the Notes to Consolidated Financial Statements, for
additional information about income tax-related contingencies.
60
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:
(cid:120) U.S. Federal Clean Air Act, which governs air emissions.
(cid:120) U.S. Federal Clean Water Act, which governs discharges to water bodies.
(cid:120) European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals
(REACH).
(cid:120) U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or
Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances
at sites where hazardous substance releases have occurred or are threatening to occur.
(cid:120) U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage
and disposal of solid waste.
(cid:120) U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore
facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and
owners and operators of vessels are liable for removal costs and damages that result from a discharge
of oil into navigable waters of the United States.
(cid:120) U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires
facilities to report toxic chemical inventories with local emergency planning committees and response
departments.
(cid:120) U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground
injection wells.
(cid:120) U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S.
waters and impose liability for the cost of pollution cleanup resulting from operations, as well as
potential liability for pollution damages.
(cid:120) European Union Trading Directive resulting in European Emissions Trading Scheme.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water,
establish water quality limits. They also, in most cases, require permits in association with new or modified
operations. These permits can require an applicant to collect substantial information in connection with the
application process, which can be expensive and time consuming. In addition, there can be delays associated
with notice and comment periods and the agency’s processing of the application. Many of the delays
associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws
and regulations governing these same types of activities. While similar, in some cases these regulations may
impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or
transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor
easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel
regulations, continue to evolve. However, environmental laws and regulations, including those that may arise
to address concerns about global climate change, are expected to continue to have an increasing impact on our
operations in the United States and in other countries in which we operate. Notable areas of potential impacts
include air emission compliance and remediation obligations in the United States and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of
oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal or
national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing
currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many
decades, a number of new laws, regulations and permitting requirements are under consideration by the U.S.
Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in
increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas
61
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, 2017, 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 $398 million in 2017 and are expected to be about $451 million per year
in 2018 and 2019. Capitalized environmental costs were $170 million in 2017 and are expected to be about
$223 million per year in 2018 and 2019.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other
third parties and are not discounted (except those assumed in a purchase business combination, which we do
record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state or international laws that require us to
undertake certain investigative and remedial activities at sites where we conduct, or once conducted,
operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number
of sites we identified that may require environmental remediation, but which are not currently the subject of
CERCLA, RCRA or other agency enforcement activities. If applicable, we accrue receivables for probable
insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA
and RCRA.
Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique
site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies,
and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable
estimates of future site remediation costs.
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At December 31, 2017, our balance sheet included total accrued environmental costs of $180 million,
compared with $247 million at December 31, 2016, 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:
(cid:120) European Emissions Trading Scheme (ETS), the program through which many of the European Union
(EU) member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS
in 2017 was approximately $1.5 million (net share before-tax).
(cid:120) The Alberta Specified Gas Emitter regulations require any existing facility with emissions equal to or
greater than 100,000 metric tonnes of carbon dioxide or equivalent per year to reduce its net emissions
intensity from its baseline. The reduction requirement increased from 15 percent in 2016 to
20 percent in 2017. The total cost of compliance with these regulations in 2017 was approximately
$3 million.
(cid:120) The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007),
confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the
Federal Clean Air Act.
(cid:120) The U.S. EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that
Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2,
2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on
April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-
based claims for damages, and may result in longer agency review time for development projects.
(cid:120) The U.S. EPA’s announcement on January 14, 2015, outlining a series of steps it plans to take to
address methane and smog-forming volatile organic compound emissions from the oil and gas
industry. The former U.S. administration established a goal of reducing the 2012 levels in methane
emissions from the oil and gas industry by 40 to 45 percent by 2025.
(cid:120) Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation
in 2017 was approximately $29 million (net share before-tax). We also incur a carbon tax for
emissions from fossil fuel combustion in our British Columbia and Alberta Operations totaling just
over $1 million (net share before-tax).
(cid:120) The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United
Nations Framework on Climate Change, setting out a new process for achieving global emission
reductions.
In the United States, some additional form of regulation may be forthcoming in the future at the federal and
state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in
the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain
compliance with laws and regulations, or required acquisition or trading of emission allowances. We are
working to continuously improve operational and energy efficiency through resource and energy conservation
throughout our operations.
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Compliance with changes in laws and regulations that create a GHG tax, 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:
(cid:120) Whether and to what extent legislation or regulation is enacted.
(cid:120) The timing of the introduction of such legislation or regulation.
(cid:120) The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation.
(cid:120) The price placed on GHG emissions (either by the market or through a tax).
(cid:120) The GHG reductions required.
(cid:120) The price and availability of offsets.
(cid:120) The amount and allocation of allowances.
(cid:120) Technological and scientific developments leading to new products or services.
(cid:120) Any potential significant physical effects of climate change (such as increased severe weather events,
changes in sea levels and changes in temperature).
(cid:120) Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of
our products and services.
The company has responded by putting in place a corporate Climate Change Action Plan, together with
individual business unit climate change management plans in order to undertake actions in four major areas:
(cid:120) Equipping the company for a low emission world, for example by integrating GHG forecasting and
reporting into company procedures; utilizing GHG pricing in planning economics; and developing
systems to handle GHG market transactions.
(cid:120) Reducing GHG emissions—In 2016, the company reduced or avoided GHG emissions by
approximately 114,000 metric tonnes by carrying out a range of programs across our business units.
In 2017, we set a long-term target to reduce our greenhouse gas emissions intensity between 5 percent
and 15 percent by 2030 from a 2017 baseline. Setting such a target demonstrates our continuing
systematic approach to managing climate-related risks throughout the business.
(cid:120) Evaluating business opportunities such as the creation of offsets and allowances, the use of low carbon
energy and the development of low carbon technologies.
(cid:120) Engaging externally—The company is a sponsor of MIT’s Joint Program on the Science and Policy of
Global Change; constructively engages in the development of climate change legislation and
regulation; and discloses our progress and performance through the Carbon Disclosure Project and the
Dow Jones Sustainability Index.
The company uses an estimated market cost of GHG emissions of $40 per metric tonne to evaluate future
projects and opportunities.
In 2017 and early 2018, cities and/or counties in California and New York have filed lawsuits against oil and
gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged
climate change impacts. ConocoPhillips will be vigorously defending against these lawsuits.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards.
Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more
likely than not, be realized. Based on our historical taxable income, our expectations for the future, and
available tax-planning strategies, management expects the net deferred tax assets will be realized as offsets to
reversing deferred tax liabilities.
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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. In January 2018, ASU No. 2016-02 was amended by
the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” We
plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, and continue to evaluate the ASU to
determine the impact of adoption on our consolidated financial statements and disclosures, accounting policies
and systems, business processes, and internal controls. We also continue to monitor proposals issued by the
FASB to clarify the ASU and certain industry implementation issues. While our evaluation of ASU No. 2016-
02 and related implementation activities are ongoing, we expect the adoption of the ASU to have a material
impact on our consolidated financial statements and disclosures. For additional information, see Note 24—
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.
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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 2017, 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 $503 million and the accumulated impairment
reserve was $130 million. The weighted-average judgmental percentage probability of ultimate failure was
approximately 57 percent, and the weighted-average amortization period was approximately three years. If
that judgmental percentage were to be raised by 5 percent across all calculations, before-tax leasehold
impairment expense in 2018 would increase by approximately $6 million. At year-end 2017, the remaining
$3,249 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 $2.4 billion is
concentrated in nine major development areas, the majority of which are not expected to move to proved
properties in 2018. 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 2017, total suspended well costs were $853 million, compared with $1,063 million at year-end
2016. For additional information on suspended wells, including an aging analysis, see Note 7—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.
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Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of
“proved” reserve estimates due to the importance of these estimates to better understand the perceived value
and future cash flows of a company’s operations. There are several authoritative guidelines regarding the
engineering criteria that must be met before estimated reserves can be designated as “proved.” Our
geosciences and reservoir engineering organization has policies and procedures in place consistent with these
authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our
proved reserves held by consolidated companies, as well as our share of equity affiliates.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes
occur, and take into account recent production and subsurface information about each field. Also, as required
by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for
economic reasons is based on 12-month average prices and current costs. This estimated date when production
will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to
year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline
and increase as prices rise.
Our proved reserves include estimated quantities related to production sharing contracts, reported under the
“economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity
prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable
to recovery of costs will change inversely to changes in commodity prices. We would expect reserves from
these contracts to decrease when product prices rise and increase when prices decline.
The estimation of proved developed reserves also is important to the income statement because the proved
developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of the
DD&A of the capitalized costs for that asset. At year-end 2017, the net book value of productive properties,
plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $41 billion and
the DD&A recorded on these assets in 2017 was approximately $6.4 billion. The estimated proved developed
reserves for our consolidated operations were 3.7 billion BOE at the end of 2016 and 3.0 billion BOE at the
end of 2017. 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 2017 would have increased by an estimated
$726 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 8—
Impairments, in the Notes to Consolidated Financial Statements, for additional information.
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Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment
when there is evidence of a loss in value and annually following updates to corporate planning assumptions.
Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of
sustained earnings capacity which would justify the current investment amount, or a current fair value less than
the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an
impairment charge is recognized for the difference between the investment’s carrying value and its estimated
fair value. When determining whether a decline in value is other than temporary, management considers
factors such as the length of time and extent of the decline, the investee’s financial condition and near-term
prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for
any anticipated recovery in the market value of the investment. Since quoted market prices are usually not
available, the fair value is typically based on the present value of expected future cash flows using discount
rates believed to be consistent with those used by principal market participants, plus market analysis of
comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the
amount of an impairment of an investment in any period. See the “APLNG” section of Note 5—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 9—
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
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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
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
$1,200 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
$110 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit
expense by $60 million. In determining the discount rate, we use yields on high-quality fixed income
investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility
that lump sum retirement benefits taken from pension plans during the year could exceed the total of service
and interest components of annual pension expense and trigger accelerated recognition of a portion of
unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan
participants and are therefore difficult to predict. 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 17—Employee Benefit Plans, in the Notes to Consolidated Financial Statements, for additional
information.
Contingencies
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.”
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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:
(cid:120) Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, including a
prolonged decline in these prices relative to historical or future expected levels.
(cid:120) The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and natural gas
liquids, which may result in recognition of impairment costs on our long-lived assets, leaseholds and
nonconsolidated equity investments.
(cid:120) Potential failures or delays in achieving expected reserve or production levels from existing and future
oil and gas developments, including due to operating hazards, drilling risks and the inherent
uncertainties in predicting reserves and reservoir performance.
(cid:120) Reductions in reserves replacement rates, whether as a result of the significant declines in commodity
prices or otherwise.
(cid:120) Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
(cid:120) Unexpected changes in costs or technical requirements for constructing, modifying or operating
exploration and production facilities.
(cid:120) Legislative and regulatory initiatives addressing environmental concerns, including initiatives
addressing the impact of global climate change or further regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
(cid:120) Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas,
(cid:120)
LNG and natural gas liquids.
Inability to timely obtain or maintain permits, including those necessary for construction, drilling
and/or development; failure to comply with applicable laws and regulations; or inability to make
capital expenditures required to maintain compliance with any necessary permits or applicable laws or
regulations.
(cid:120) Failure to complete definitive agreements and feasibility studies for, and to complete construction of,
announced and future exploration and production and LNG development in a timely manner (if at all)
or on budget.
(cid:120) Potential disruption or interruption of our operations due to accidents, extraordinary weather events,
civil unrest, political events, war, terrorism, cyber attacks, and information technology failures,
constraints or disruptions.
(cid:120) Changes in international monetary conditions and foreign currency exchange rate fluctuations.
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(cid:120) Reduced demand for our products or the use of competing energy products, including alternative
energy sources.
(cid:120) Substantial investment in and development of alternative energy sources, including as a result of
existing or future environmental rules and regulations.
(cid:120) Liability for remedial actions, including removal and reclamation obligations, under environmental
regulations.
(cid:120) Liability resulting from litigation.
(cid:120) General domestic and international economic and political developments, including armed hostilities;
expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas,
LNG and natural gas liquids pricing, regulation or taxation; and other political, economic or
diplomatic developments.
(cid:120) Volatility in the commodity futures markets.
(cid:120) Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules
applicable to our business, including changes resulting from the implementation and interpretation of
the Tax Cuts and Jobs Act.
(cid:120) Competition in the oil and gas exploration and production industry.
(cid:120) Any limitations on our access to capital or increase in our cost of capital related to illiquidity or
uncertainty in the domestic or international financial markets.
(cid:120) Our inability to execute, or delays in the completion, of any asset dispositions we elect to pursue.
(cid:120) Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for asset
dispositions or that such approvals may require modification to the terms of the transactions or the
operation of our remaining business.
(cid:120) Potential disruption of our operations as a result of asset dispositions, including the diversion of
management time and attention.
(cid:120) Our inability to deploy the net proceeds from any asset dispositions we undertake in the manner and
timeframe we currently anticipate, if at all.
(cid:120) Our inability to liquidate the common stock issued to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem acceptable, or at all.
(cid:120) Our inability to obtain economical financing for development, construction or modification of
facilities and general corporate purposes.
(cid:120) The operation and financing of our joint ventures.
(cid:120) The ability of our customers and other contractual counterparties to satisfy their obligations to us.
(cid:120) Our inability to realize anticipated cost savings and expenditure reductions.
(cid:120) The factors generally described in Item 1A—Risk Factors in our 2017 Annual Report on Form 10-K
and any additional risks described in our other filings with the SEC.
71
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, monitor 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:
(cid:120) Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we
use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas
consumers, to floating market prices.
(cid:120) Enable us to use market knowledge to capture opportunities such as moving physical commodities to
more profitable locations and storing commodities to capture seasonal or time premiums. We may use
derivatives to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the
effect of adverse changes in market conditions on the derivative financial instruments and derivative
commodity instruments we hold or issue, including commodity purchases and sales contracts recorded on the
balance sheet at December 31, 2017, 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, 2017 and 2016, 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.
72
Expected Maturity Date
Year-End 2017
2018
2019
2020
2021
2022
Remaining years
Total
Fair value
Year-End 2016
2017
2018
2019
2020
2021
Remaining years
Total
Fair value
Millions of Dollars Except as Indicated
Debt
Fixed Average
Interest
Rate
Rate
Maturity
Floating
Rate
Maturity
Average
Interest
Rate
$
$
$
$
$
$
2,250
23
-
150
1,014
14,207
17,644
21,402
1,001
1,570
2,250
1,500
2,150
15,221
23,692
26,824
3.31 % $
-
-
9.13
2.45
6.00
$
$
1.06 % $
3.63
5.75
4.73
4.08
5.77
$
$
250
-
-
-
500
283
1,033
1,033
-
250
1,450
-
-
783
2,483
2,483
1.75 %
-
-
-
2.32
1.70
- %
1.24
2.31
-
-
1.43
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, and investments in available-for-sale securities.
At December 31, 2017 and 2016, we held foreign currency exchange forwards hedging cross-border
commercial activity and foreign currency exchange swaps and options for purposes of mitigating our cash-
related exposures. Although these forwards, swaps and options 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.
At December 31, 2017, we had outstanding foreign currency zero-cost collars buying the right to sell
$1.25 billion Canadian dollars (CAD) at $0.707 CAD and selling the right to buy $1.25 billion CAD at
$0.842 CAD against the U.S. dollar. Based on the assumed volatility in the fair value calculation, the net fair
value of these foreign currency contracts as at December 31, 2017, was a before-tax loss of $9 million. Based
on an adverse hypothetical 10 percent change in the December 2017 exchange rate, this would result in an
additional before-tax loss of $74 million. The sensitivity analysis is based on changing one assumption while
holding all other assumptions constant, which in practice may be unlikely to occur, as changes in some of the
assumptions may be correlated.
At December 31, 2016, we had outstanding foreign currency exchange forward-swap contracts. Since the gain
or loss on the swaps was offset from remeasuring the related cash balances and since our aggregate position in
the forwards was not material, there would have been no impact to our income from an adverse hypothetical
10 percent change in the December 2016 exchange rates.
73
The gross notional and fair market values of these positions at December 31, 2017 and 2016, were as follows:
Foreign Currency Exchange Derivatives
In Millions
Notional*
2017
Fair Market Value**
2016
2017
2016
Sell U.S. dollar, buy Canadian dollar
Buy U.S. dollar, sell British pound
Sell Canadian dollar, buy U.S. dollar
Buy Canadian dollar, sell U.S. dollar
Buy British pound, sell Canadian dollar
Sell British pound, buy Norwegian krone
Sell British pound, buy Euro
*Denominated in U.S. dollars (USD), British pound (GBP) and Canadian dollars (CAD).
**Denominated in U.S. dollars.
-
-
1,250
25
-
-
1
USD
USD
CAD
CAD
GBP
GBP
GBP
13
25
-
-
1,069
51
-
-
-
(9)
1
-
-
-
-
-
-
-
(168)
1
-
For additional information about our use of derivative instruments, see Note 13—Derivative and Financial
Instruments, in the Notes to Consolidated Financial Statements.
74
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
Report of Management ...........................................................................................................................
Page
76
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm .................................................................
78
Consolidated Income Statement for the years ended December 31, 2017, 2016 and 2015 ....................
79
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2017, 2016 and 2015 ..................................................................................................
80
Consolidated Balance Sheet at December 31, 2017 and 2016 ................................................................
81
Consolidated Statement of Cash Flows for the years ended December 31, 2017, 2016 and 2015 .........
82
Consolidated Statement of Changes in Equity for the years ended
December 31, 2017, 2016 and 2015 ..................................................................................................
83
Notes to Consolidated Financial Statements ...........................................................................................
84
Supplementary Information
Oil and Gas Operations .............................................................................................................
140
Selected Quarterly Financial Data .............................................................................................
167
Condensed Consolidating Financial Information ......................................................................
168
75
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information
appearing in this annual report. The consolidated financial statements present fairly the company’s financial
position, results of operations and cash flows in conformity with accounting principles generally accepted in
the United States. In preparing its consolidated financial statements, the company includes amounts that are
based on estimates and judgments management believes are reasonable under the circumstances. The
company’s financial statements have been audited by Ernst & Young LLP, an independent registered public
accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by
stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records
and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial
reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the
company’s management and directors regarding the preparation and fair presentation of published financial
statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of
December 31, 2017. 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, 2017.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2017, and their report is included herein.
/s/ Ryan M. Lance
/s/ Don E. Wallette, Jr.
Ryan M. Lance
Chairman and
Chief Executive Officer
February 20, 2018
Don E. Wallette, Jr.
Executive Vice President, Finance,
Commercial and
Chief Financial Officer
76
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of ConocoPhillips
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2017 and
2016, and the related consolidated income statement, consolidated statements of comprehensive income, changes in
equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes,
condensed consolidating financial information listed in the Index at Item 8, and financial statement schedule listed in
Item 15(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to
above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31,
2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the
period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), ConocoPhillips’ internal control over financial reporting as of December 31, 2017, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report dated February 20, 2018, expressed
an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of ConocoPhillips’ management. Our responsibility is to express an
opinion on ConocoPhillips’ financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to ConocoPhillips in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as ConocoPhillips’ auditor since 1949.
Houston, Texas
February 20, 2018
77
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of ConocoPhillips
Opinion on Internal Control over Financial Reporting
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2017, 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). In our opinion, ConocoPhillips
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,
based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated
income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of
the three years in the period ended December 31, 2017, and the related notes, condensed consolidating financial
information listed in the Index at Item 8, and financial statement schedule listed in Item 15(a) of ConocoPhillips and
our report dated February 20, 2018, expressed an unqualified opinion thereon.
Basis for Opinion
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 ConocoPhillips’ internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect
to ConocoPhillips in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 20, 2018
78
Consolidated Income Statement
ConocoPhillips
Years Ended December 31
Revenues and Other Income
Sales and other operating revenues
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
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Other expense
Total Costs and Expenses
Loss before income taxes
Income tax benefit
Net loss
Less: net income attributable to noncontrolling interests
Net Loss Attributable to ConocoPhillips
Net Loss Attributable to ConocoPhillips Per Share
of Common Stock (dollars)
Basic
Diluted
Dividends Paid Per Share of Common Stock (dollars)
Average Common Shares Outstanding (in thousands)
Basic
Diluted
See Notes to Consolidated Financial Statements.
$
$
$
$
Millions of Dollars
2017
2016
29,106
772
2,177
529
32,584
12,475
5,173
561
938
6,845
6,601
809
362
1,098
35
302
35,199
(2,615)
(1,822)
(793)
(62)
(855)
23,693
52
360
255
24,360
9,994
5,667
723
1,915
9,062
139
739
425
1,245
(19)
-
29,890
(5,530)
(1,971)
(3,559)
(56)
(3,615)
(0.70)
(0.70)
1.06
(2.91)
(2.91)
1.00
2015
29,564
655
591
125
30,935
12,426
7,016
953
4,192
9,113
2,245
901
483
920
(75)
-
38,174
(7,239)
(2,868)
(4,371)
(57)
(4,428)
(3.58)
(3.58)
2.94
1,221,038
1,221,038
1,245,440
1,245,440
1,241,919
1,241,919
79
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years Ended December 31
Millions of Dollars
2017
2016
2015
$
2
(793)
(38)
(36)
19
Net Loss
Other comprehensive income (loss)
Defined benefit plans
Prior service credit arising during the period
Reclassification adjustment for amortization of prior
service credit included in net loss
Net change
Net actuarial gain (loss) arising during the period
Reclassification adjustment for amortization of net
actuarial losses included in net loss
Net change
Nonsponsored plans*
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Unrealized holding loss on securities
Unrealized loss on securities, net of tax
Foreign currency translation adjustments
Reclassification adjustment for gain included in net loss
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Loss
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Loss Attributable to ConocoPhillips
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
247
266
(2)
(81)
147
(58)
(58)
586
-
-
586
675
(118)
(62)
(180)
$
(3,559)
(4,371)
23
(35)
(12)
(481)
309
(172)
2
78
(104)
-
-
153
5
-
158
54
(3,505)
(56)
(3,561)
301
(19)
282
592
403
995
1
(460)
818
-
-
(5,199)
-
36
(5,163)
(4,345)
(8,716)
(57)
(8,773)
80
Consolidated Balance Sheet
At December 31
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable (net of allowance of $4 million in 2017
and $5 million in 2016)
Accounts and notes receivable—related parties
Investment in Cenovus Energy
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, depletion
and amortization of $64,748 million in 2017 and $73,075 million in 2016)
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2017—1,785,419,175 shares; 2016—1,782,079,107 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2017—608,312,034 shares; 2016—544,809,771 shares)
Accumulated other comprehensive loss
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.
ConocoPhillips
Millions of Dollars
2017
2016
6,325
1,873
4,179
141
1,899
1,060
1,035
16,512
9,599
461
45,683
1,107
73,362
4,009
21
2,575
1,038
725
1,029
9,397
17,128
7,631
5,282
1,854
1,269
42,561
3,610
50
3,249
165
-
1,018
517
8,609
21,091
581
58,331
1,160
89,772
3,631
22
1,089
484
689
994
6,909
26,186
8,425
8,949
2,552
1,525
54,546
18
46,622
(39,906)
(5,518)
29,391
30,607
194
30,801
73,362
18
46,507
(36,906)
(6,193)
31,548
34,974
252
35,226
89,772
$
$
$
$
81
Consolidated Statement of Cash Flows
ConocoPhillips
Years Ended December 31
Cash Flows From Operating Activities
Net loss
Adjustments to reconcile net loss to net cash provided by
operating activities
Depreciation, depletion and amortization
Impairments
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
Undistributed equity earnings
Gain on dispositions
Other
Working capital adjustments
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease in prepaid expenses and other current assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net purchases of short-term investments
Collection of advances/loans—related parties
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Provided by (Used in) Financing Activities
Millions of Dollars
2017
2016
2015
$
(793)
(3,559)
(4,371)
6,845
6,601
566
362
(3,681)
(232)
(2,177)
(429)
(886)
(55)
69
265
622
7,077
(4,591)
132
13,860
(1,790)
115
36
7,762
-
(7,876)
(63)
(3,000)
(1,305)
(112)
(12,356)
9,062
139
1,184
425
(2,221)
299
(360)
(85)
820
44
105
(524)
(926)
4,403
(4,869)
(331)
1,286
(51)
108
(2)
(3,859)
4,594
(2,251)
(63)
(126)
(1,253)
(137)
764
9,113
2,245
3,065
483
(2,772)
101
(591)
321
1,810
166
239
(1,647)
(590)
7,572
(10,050)
(968)
1,952
-
105
306
(8,655)
2,498
(103)
(82)
-
(3,664)
(78)
(1,429)
Effect of Exchange Rate Changes on Cash and Cash Equivalents
232
(66)
(182)
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
See Notes to Consolidated Financial Statements.
2,715
3,610
6,325
1,242
2,368
3,610
(2,694)
5,062
2,368
$
82
Consolidated Statement of Changes in Equity
ConocoPhillips
Attributable to ConocoPhillips
Millions of Dollars
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
$
18
46,071
(36,780)
(1,902)
(4,345)
286
$
18
46,357
(36,780)
(6,247)
54
(126)
150
$
18
46,507
(36,906)
(6,193)
675
(3,000)
115
$
18
46,622
(39,906)
(5,518)
Retained
Earnings
44,504
(4,428)
(3,664)
2
36,414
(3,615)
(1,253)
2
31,548
(855)
(1,305)
3
29,391
Non-
Controlling
Interests
362
57
(100)
1
320
56
(124)
252
62
(120)
194
Total
52,273
(4,371)
(4,345)
(3,664)
(100)
286
3
40,082
(3,559)
54
(1,253)
(126)
(124)
150
2
35,226
(793)
675
(1,305)
(3,000)
(120)
115
3
30,801
December 31, 2014
Net income (loss)
Other comprehensive loss
Dividends paid
Distributions to noncontrolling interests and other
Distributed under benefit plans
Other
December 31, 2015
Net income (loss)
Other comprehensive income
Dividends paid
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Other
December 31, 2016
Net income (loss)
Other comprehensive income
Dividends paid
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Other
December 31, 2017
See Notes to Consolidated Financial Statements.
83
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1—Accounting Policies
(cid:132) Consolidation Principles and Investments—Our consolidated financial statements include the accounts
of majority-owned, controlled subsidiaries and variable interest entities where we are the primary
beneficiary. The equity method is used to account for investments in affiliates in which we have the
ability to exert significant influence over the affiliates’ operating and financial policies. When we do not
have the ability to exert significant influence, the investment is either classified as available-for-sale if
fair value is readily determinable, or the cost method is used if fair value is not readily determinable.
Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are
consolidated on a proportionate basis. Other securities and investments are generally carried at cost.
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 23—Segment Disclosures and Related Information.
(cid:132) Foreign Currency Translation—Adjustments resulting from the process of translating foreign
functional currency financial statements into U.S. dollars are included in accumulated other
comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses
are included in current earnings. Most of our foreign operations use their local currency as the functional
currency.
(cid:132) Use of Estimates—The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent
assets and liabilities. Actual results could differ from these estimates.
(cid:132) Revenue Recognition—Revenues associated with sales of crude oil, bitumen, natural gas, liquefied
natural gas (LNG), natural gas liquids and other items are recognized when title passes to the customer,
which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either
immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues associated with producing properties in which we have an interest with other producers are
recognized based on the actual volumes we sold during the period. Any differences between volumes
sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable
through remaining production, are recognized as accounts receivable or accounts payable, as appropriate.
Cumulative differences between volumes sold and entitlement volumes are generally not significant.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale
of inventory with the same counterparty are entered into “in contemplation” of one another, are combined
and reported net (i.e., on the same income statement line).
(cid:132) Shipping and Handling Costs—We include shipping and handling costs in production and operating
expenses for production activities. Transportation costs related to marketing activities are recorded in
purchased commodities. Freight costs billed to customers are recorded as a component of revenue.
(cid:132) Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily
convertible to known amounts of cash and have original maturities of 90 days or less from their date of
purchase. They are carried at cost plus accrued interest, which approximates fair value.
(cid:132) Short-Term Investments—Investments in bank time deposits and marketable securities (commercial
paper and government obligations) with original maturities of greater than 90 days but less than one year
are classified as short-term investments.
84
(cid:132)
Inventories—We have several valuation methods for our various types of inventories and consistently
use the following methods for each type of inventory. Our commodity-related inventories are recorded at
cost primarily using the last-in, first-out (LIFO) basis. We measure these inventories at the lower-of-cost-
or-market in the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded
as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs
with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or
product to its existing condition and location, but not unusual/nonrecurring costs or research and
development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and
well equipment, are valued using various methods, including the weighted-average-cost method, and the
first-in, first-out (FIFO) method, consistent with industry practice.
(cid:132) Fair Value Measurements—Assets and liabilities measured at fair value and required to be categorized
within the fair value hierarchy are categorized into one of three different levels depending on the
observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active
markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices
included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated
inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications
to observable related market data or our assumptions about pricing by market participants.
(cid:132) Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the
right of offset exists and certain other criteria are met, derivative assets and liabilities with the same
counterparty are netted on the balance sheet and the collateral payable or receivable is netted against
derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to
fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives
not accounted for as hedges are recognized immediately in earnings.
(cid:132) Oil and Gas Exploration and Development—Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting.
Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in
the balance sheet caption properties, plants and equipment (PP&E). Leasehold impairment is
recognized based on exploratory experience and management’s judgment. Upon achievement of all
conditions necessary for reserves to be classified as proved, the associated leasehold costs are
reclassified to proved properties.
Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further evaluation of whether economically recoverable
reserves have been found. If economically recoverable reserves are not found, exploratory well costs
are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and
gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the
reserves and the economic and operating viability of the project is being made. For complex
exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance
sheet for several years while we perform additional appraisal drilling and seismic work on the
potential oil and gas field or while we seek government or co-venturer approval of development plans
or seek environmental permitting. Once all required approvals and permits have been obtained, the
projects are moved into the development phase, and the oil and gas resources are designated as proved
reserves.
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 7—
Suspended Wells and Other Exploration Expenses, for additional information on suspended wells.
85
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.
(cid:132) Capitalized Interest—Interest from external borrowings is capitalized on major projects with an
expected construction period of one year or longer. Capitalized interest is added to the cost of the
underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying
assets.
(cid:132) Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon
properties and certain pipeline assets (those which are expected to have a declining utilization pattern),
are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are
determined by either the individual-unit-straight-line method or the group-straight-line method (for those
individual units that are highly integrated with other units).
(cid:132)
Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for
impairment whenever changes in facts and circumstances indicate a possible significant deterioration in
the future cash flows expected to be generated by an asset group and annually in the fourth quarter
following updates to corporate planning assumptions. If there is an indication the carrying amount of an
asset may not be recovered, the asset is monitored by management through an established process where
changes to significant assumptions such as prices, volumes and future development plans are reviewed.
If, upon review, the sum of the undiscounted before-tax cash flows is less than the carrying value of the
asset group, the carrying value is written down to estimated fair value through additional amortization or
depreciation provisions and reported as impairments in the periods in which the determination of the
impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which
there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—
generally on a field-by-field basis for exploration and production assets. Because there usually is a lack
of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined
based on the present values of expected future cash flows using discount rates believed to be consistent
with those used by principal market participants or based on a multiple of operating cash flow validated
with historical market transactions of similar assets where possible. Long-lived assets committed by
management for disposal within one year are accounted for at the lower of amortized cost or fair value,
less cost to sell, with fair value determined using a binding negotiated price, if available, or present value
of expected future cash flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based
on estimated future production volumes, prices and costs, considering all available evidence at the date of
review. The impairment review includes cash flows from proved developed and undeveloped reserves,
including any development expenditures necessary to achieve that production. Additionally, when
probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be
included in the impairment calculation.
(cid:132)
Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has
occurred and annually following updates to corporate planning assumptions. When such a condition is
judgmentally determined to be other than temporary, the carrying value of the investment is written down
to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or
upon the present value of expected future cash flows using discount rates believed to be consistent with
those used by principal market participants, plus market analysis of comparable assets owned by the
investee, if appropriate.
86
(cid:132) Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements,
are expensed when incurred.
(cid:132) Property Dispositions—When complete units of depreciable property are sold, the asset cost and related
accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line
of our consolidated income statement. When less than complete units of depreciable property are
disposed of or retired, the difference between asset cost and salvage value is charged or credited to
accumulated depreciation.
(cid:132) Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire
and remove long-lived assets are recorded in the period in which the obligation is incurred (typically
when the asset is installed at the production location). When the liability is initially recorded, we
capitalize this cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our
estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time
the liability is increased for the change in its present value, and the capitalized cost in PP&E is
depreciated over the useful life of the related asset. For additional information, see Note 9—Asset
Retirement Obligations and Accrued Environmental Costs.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.
Expenditures relating to an existing condition caused by past operations, and those having no future
economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an
undiscounted basis (unless acquired in a purchase business combination, 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.
(cid:132) Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the
guarantee is given. The initial liability is subsequently reduced as we are released from exposure under
the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on
the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is
indefinite, we reverse the liability when we have information indicating the liability is essentially relieved
or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over
time. We amortize the guarantee liability to the related income statement line item based on the nature of
the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We
reverse the fair value liability only when there is no further exposure under the guarantee.
(cid:132) Share-Based Compensation—We recognize share-based compensation expense over the shorter of the
service period (i.e., the stated period of time required to earn the award) or the period beginning at the
start of the service period and ending when an employee first becomes eligible for retirement. We have
elected to recognize expense on a straight-line basis over the service period for the entire award, whether
the award was granted with ratable or cliff vesting.
(cid:132)
Income Taxes—Deferred income taxes are computed using the liability method and are provided on all
temporary differences between the financial reporting basis and the tax basis of our assets and liabilities,
except for deferred taxes on income and temporary differences related to the cumulative translation
adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate
joint ventures. Allowable tax credits are applied currently as reductions of the provision for income
taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties
related to unrecognized tax benefits are reflected in production and operating expenses.
(cid:132) Taxes Collected from Customers and Remitted to Governmental Authorities—Sales and value-
added taxes are recorded net.
87
(cid:132) Net Income (Loss) Per Share of Common Stock—Basic net income (loss) per share of common stock
is calculated based upon the daily weighted-average number of common shares outstanding during the
year. Also, this calculation includes fully vested stock and unit awards that have not yet been issued as
common stock, along with an adjustment to net income (loss) for dividend equivalents paid on unvested
unit awards that are considered participating securities. Diluted net income per share of common stock
includes unvested stock, unit or option awards granted under our compensation plans and vested but
unexercised stock options, but only to the extent these instruments dilute net income per share, primarily
under the treasury-stock method. Diluted net loss per share, which is calculated the same as basic net loss
per share, does not assume conversion or exercise of securities that would have an antidilutive effect.
Treasury stock is excluded from the daily weighted-average number of common shares outstanding in
both calculations. The earnings per share impact of the participating securities is immaterial.
Note 2—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, 2017, 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 5—Investments, Loans and Long-Term Receivables, and Note 11—
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. In
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, 2017, the book value of our equity method investment in MWCC was $139 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.
88
Note 3—Inventories
Inventories at December 31 were:
Crude oil and natural gas
Materials and supplies
Millions of Dollars
2017
512
548
1,060
$
$
2016
418
600
1,018
Inventories valued on the LIFO basis totaled $341 million and $269 million at December 31, 2017 and 2016,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories was
approximately $124 million and $104 million at December 31, 2017 and December 31, 2016, respectively. In
2017, liquidation of LIFO inventory values increased the net loss attributable to ConocoPhillips by $1 million.
Note 4—Assets Held for Sale, Sold or Acquired
Assets Held for Sale
In the second quarter of 2017, we signed a definitive agreement to sell our interest in the Barnett. We
terminated this agreement in the fourth quarter of 2017 and are continuing to market the asset in 2018. In
connection with the signing of the definitive agreement, we recorded a before-tax impairment of $572 million
to reduce the carrying value of our investment to estimated fair value. As of December 31, 2017, our Barnett
interests had a net carrying value of approximately $291 million and were considered held for sale resulting in
the reclassification of $339 million of PP&E to “Prepaid expenses and other current assets” and $48 million of
noncurrent liabilities, primarily asset retirement obligations (ARO), to “Other accruals” on our consolidated
balance sheet. The before-tax loss associated with our interests in the Barnett, including the $572 million
impairment noted above, was $566 million, $66 million, and $58 million for the years ended December 31,
2017, 2016 and 2015, respectively. The Barnett results of operations are reported within our Lower 48
segment.
In addition to the Barnett, certain other properties in our Lower 48 segment met the criteria for assets held for
sale at December 31, 2017. These properties had a net carrying value of approximately $212 million after
recording a before-tax impairment of $78 million to reduce the carrying value to estimated fair value in the
fourth quarter of 2017. We reclassified $238 million of PP&E to “Prepaid expenses and other current assets”
and $26 million of noncurrent liabilities, primarily AROs, to “Other accruals” on our consolidated balance
sheet. In January 2018, we completed the sale of a portion of these properties for net proceeds of $112 million.
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. All cash proceeds are included in the “Cash Flows From Investing Activities”
section of our consolidated statement of cash flows.
2017
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina
Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.
Consideration for the transaction was $11.0 billion in cash after customary adjustments, 208 million Cenovus
Energy common shares and a five-year uncapped contingent payment. The value of the shares at closing was
$1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. The contingent payment,
calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by which the
Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel.
89
At closing, the carrying value of our equity investment in FCCL was $8.9 billion. The carrying value of our
interest in the western Canada gas assets was $1.9 billion consisting primarily of $2.6 billion of PP&E, partly
offset by AROs of $585 million and approximately $100 million of environmental and other accruals. A
before-tax gain of $2.1 billion was included in the “Gain on disposition” line on our consolidated income
statement in 2017. We reported before-tax losses of $26 million, $572 million and $582 million for the
western Canada gas producing properties for the years ended December 31, 2017, 2016 and 2015, respectively.
We reported before-tax equity earnings of $197 million, $89 million and $78 million for FCCL for the same
periods, respectively. Both FCCL and the western Canada gas assets were reported within our Canada
segment.
For more information on the Canada disposition and our investment in Cenovus Energy see Note 6—
Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 19—Accumulated Other
Comprehensive Loss.
On July 31, 2017, we completed the sale of our interests in the San Juan Basin to an affiliate of Hilcorp Energy
Company for $2.5 billion in cash after customary adjustments, and recognized a loss on disposition of
$22 million. The transaction includes a contingent payment of up to $300 million. The six-year contingent
payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry
Hub price is at or above $3.20 per million British thermal units.
In the second quarter of 2017, we recorded a before-tax impairment of $3.3 billion to reduce the carrying value
of our interests in the San Juan Basin to fair value. At the time of disposition, the San Juan Basin interests had
a net carrying value of approximately $2.5 billion, consisting of $2.9 billion of PP&E and $406 million of
liabilities, primarily AROs. The before-tax loss associated with our interests in the San Juan Basin, including
both the $3.3 billion impairment and $22 million loss on disposition noted above, was $3.2 billion,
$239 million and $99 million for the years ended December 31, 2017, 2016 and 2015, respectively. The San
Juan Basin results of operations were reported within our Lower 48 segment.
On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash
after customary adjustments, and recognized a before-tax loss on disposition of $28 million. At the time of the
disposition, the carrying value of our interest was $206 million, consisting primarily of $279 million of PP&E
and $72 million of AROs. Including the $28 million loss on disposition noted above, we reported before-tax
losses for the Panhandle properties of $14 million, $21 million, and $41 million for the years ended December
31, 2017, 2016 and 2015, respectively. The Panhandle results were reported within our Lower 48 segment.
2016
In April 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 AROs.
In October 2016, we completed an asset exchange with Bonavista Energy in which we gave up approximately
141,000 net acres of noncore 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.
A loss on disposition of approximately $1 million was recognized upon completion of the transaction. The
divested properties were included in the Canada segment.
Also in October 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.
90
In November 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. In 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.
In December 2016, we completed the sale of certain mineral and non-mineral fee lands in northeastern
Minnesota, which were 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. 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.
2015
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.
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Acquisition
In January 2018, we entered into an agreement to acquire certain oil and gas assets in Alaska for $400 million,
subject to customary adjustments. The acquisition is subject to regulatory approval.
Note 5—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity investments
Loans and advances—related parties
Long-term receivables
Other investments
Millions of Dollars
2017
2016
$
$
9,129
461
375
95
10,060
20,364
581
631
96
21,672
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2017, included:
(cid:120) APLNG—37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec
(25 percent)—to develop coalbed methane production from the Bowen and Surat basins in
Queensland, Australia, as well as process and export LNG.
(cid:120) Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of
Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural
gas from Qatar’s North Field, as well as exports LNG.
Summarized 100 percent earnings information for equity method investments in affiliated companies,
combined, was as follows:
Revenues
Income (loss) before income taxes
Net income (loss)
Millions of Dollars
2017
2016
2015
$
11,554
(2,875)
(1,431)
10,149
660
799
11,003
1,866
1,801
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
Millions of Dollars
2017
2016
$
2,920
42,693
2,453
25,522
3,578
60,243
2,352
23,764
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.
92
At December 31, 2017, retained earnings included $20 million related to the undistributed earnings of
affiliated companies. Dividends received from affiliates were $605 million, $398 million and $876 million in
2017, 2016 and 2015, respectively.
APLNG
APLNG is focused on coalbed methane production from the Bowen and Surat basins in Queensland, Australia,
to supply the domestic gas market and on 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, 2017, all amounts have been drawn from the facility. APLNG
made its first principal and interest repayment in March 2017, and will continue to make bi-annual payments
until March 2029. At December 31, 2017, a balance of $7.9 billion was outstanding on the facility. In
connection with the execution of the project financing, we provided a completion guarantee for our pro-rata
share of the project finance facility until the project achieves financial completion. In October 2016, we
reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. In August
2017, we reached financial completion for Train 2, which removed the remaining guarantee. See Note 11—
Guarantees, for additional information.
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with
additional forms of subordinated financial support. See Note 2—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 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 first and second quarters of 2017, the outlook for crude oil prices deteriorated, and as a result of
significantly reduced price outlooks, the estimated fair value of our investment in APLNG declined to an
amount below carrying value. Based on a review of the facts and circumstances surrounding this decline in
fair value, we concluded in the second quarter of 2017 the impairment was other than temporary under the
guidance of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC)
Topic 323, “Investments – Equity Method and Joint Ventures,” and the recognition of an impairment of our
investment to fair value was necessary. Accordingly, we recorded a noncash $2,384 million, before- and after-
tax impairment in our second-quarter 2017 results. Fair value was estimated based on an internal discounted
cash flow model using 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. The impairment was included in the “Impairments” line on our consolidated income
statement.
At December 31, 2017, the carrying value of our equity method investment in APLNG was $7,669 million.
The historical cost basis of our 37.5 percent share of net assets on the books of APLNG was $7,213 million,
resulting in a basis difference of $456 million on our books. The basis difference, which is substantially all
93
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 loss attributable to ConocoPhillips for 2017, 2016 and 2015 was after-tax expense of
$100 million, $92 million and $21 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. Cenovus is the
operator and managing partner of FCCL.
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Financial information presented
within this footnote includes our historical interest up to the date of sale. For additional information on the
Canada disposition and our investment in Cenovus Energy, see Note 4—Assets Held for Sale, Sold or
Acquired and Note 6—Investment in Cenovus Energy.
QG3
QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project
financing, with a current outstanding balance of $581 million as described below under “Loans and Long-
Term Receivables.” At December 31, 2017, the book value of our equity method investment in QG3,
excluding the project financing, was $886 million. We have terminal and pipeline use agreements with Golden
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, in which we have a
12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and
regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets
outside of the United States.
Loans and Long-Term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into
numerous agreements with other parties to pursue business opportunities. Included in such activity are loans
and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is
transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan
agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will
decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated
interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan
balance may not be fully recovered.
At December 31, 2017, significant loans to affiliated companies include $581 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.”
94
Note 6—Investment in Cenovus Energy
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction
included 208 million Cenovus Energy common shares, which approximated 16.9 percent of issued and
outstanding Cenovus common shares at closing. See Note 4—Assets Held for Sale, Sold or Acquired, for
additional information on the Canada disposition.
At closing, the fair value and cost basis of our investment in 208 million Cenovus Energy common shares was
$1.96 billion based on a price of $9.41 per share on the New York Stock Exchange.
We have classified our investment as an available-for-sale equity security on our consolidated balance sheet
and, as of December 31, 2017, our investment is carried at fair value of $1.90 billion, reflecting the closing
price of Cenovus Energy shares on the New York Stock Exchange of $9.13 per share. The carrying value
reflects a before-tax and after-tax unrealized loss of $58 million over our cost basis of $1.96 billion. The
unrealized loss is reported as a component of accumulated other comprehensive loss. See Note 14—Fair
Value Measurement, for additional information. We intend to decrease our investment over time through
market transactions, private agreements or otherwise.
Note 7—Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2017, 2016 and 2015:
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
Millions of Dollars
2017
2016
2015
$
$
1,063
118
(66)
-
(262)
853
1,260
225
(27)
(247)
(148)
1,063
1,299
331
(28)
-
(342)
1,260
The following table provides an aging of suspended well balances at December 31:
Millions of Dollars
2017
2016
2015
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
$
$
67
786
853
23
132
931
1,063
235
1,025
1,260
26
28
95
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, 2017:
Greater Poseidon—Australia(2)
Greater Clair—UK(2)
Surmont—Canada(1)
NPRA—Alaska(1)
Barossa/Caldita—Australia(2)
Middle Magdalena Basin—Colombia(1)
Bohai—China(2)
Kamunsu East—Malaysia(2)
NC 98—Libya(2)
Sunrise—Australia(2)
Other of $10 million or less each(1)(2)
Total
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
$
Millions of Dollars
Suspended Since
Total
2014–2016 2011–2013
2004–2010
177
144
117
114
77
48
19
19
15
13
43
786
63
99
34
66
-
48
19
-
11
-
20
360
102
45
59
42
-
-
-
19
-
-
6
273
12
-
24
6
77
-
-
-
4
13
17
153
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 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.
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 recognized a
before-tax charge of $43 million net in the first quarter of 2017. These charges are included in the
“Exploration expenses” line on our consolidated income statement.
Note 8—Impairments
During 2017, 2016 and 2015, we recognized the following before-tax impairment charges:
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Corporate
Millions of Dollars
2017
180
3,969
22
46
2,384
-
6,601
$
$
2016
1
149
88
(160)
44
17
139
2015
10
(2)
4
724
1,508
1
2,245
96
2017
In Alaska, we recorded impairments of $180 million primarily for the associated PP&E carrying value of our
small interest in the Point Thomson unit.
In the Lower 48, we recorded impairments of $3,969 million primarily due to certain developed properties
which were written down to fair value less costs to sell. See Note 4—Assets Held for Sale, Sold or Acquired,
for additional information on our dispositions.
In Canada, we recorded impairments of $22 million primarily due to cancelled projects.
In Europe and North Africa, we recorded impairments of $46 million primarily due to reduced volume
forecasts for a field in the United Kingdom and restructured ownership and a change in commercial premises
for a gas processing plant in Norway, partly offset by decreased ARO estimates on fields at or nearing the end
of life which were impaired in prior years.
In Asia Pacific and Middle East, we recorded impairments of $2,384 million, including the impairment of our
APLNG investment. For more information, see the “APLNG” section of Note 5—Investments, Loans and
Long-Term Receivables.
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.
In our Lower 48 segment, we recorded a before-tax impairment of $51 million for the associated carrying
value of capitalized undeveloped leasehold costs of Shenandoah in deepwater Gulf of Mexico following the
suspension of appraisal activity by the operator. Additionally, we recorded a $38 million before-tax
impairment for mineral assets primarily due to plan of development changes.
2016
In the 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
ARO estimates.
In Canada, we recorded impairments of $88 million mainly due to plan of development changes, as well as
certain developed properties being written down to fair value less costs to sell.
In Europe and North Africa, we recorded a credit to impairment of $160 million, primarily in the United
Kingdom, due to decreased ARO estimates on fields at or nearing the end of life which 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 a 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.
97
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 before-tax 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 additional testing of undeveloped leaseholds.
2015
See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment included within the Asia Pacific and Middle East segment.
In Europe and North Africa, we recorded impairments of $724 million, primarily in the United Kingdom as a
result of lower natural gas prices and increases to AROs.
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.
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 before-tax 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 before-tax 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 a before-tax impairment of $105 million for the associated carrying values of
capitalized undeveloped leasehold cost.
In our Alaska segment, we recorded a before-tax 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 a before-tax impairment of $102 million for the Duvernay, Thornbury,
Saleski and Crow Lake areas driven primarily by the lack of commerciality of wells.
Note 9—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."
Millions of Dollars
2017
2016
$
$
7,798
180
7,978
(347)
7,631
8,405
247
8,652
(227)
8,425
98
Asset Retirement Obligations
We record the fair value of a liability for an ARO 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 AROs 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 2017 and 2016, our overall ARO 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
Millions of Dollars
2017
2016
$
$
8,405
358
113
(150)
(152)
(1,065)
289
7,798
9,911
420
180
(1,197)
(314)
(150)
(445)
8,405
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2017 and 2016, were $180 million and $247 million,
respectively.
We had accrued environmental costs of $105 million and $183 million at December 31, 2017 and 2016,
respectively, related to remediation activities in the United States and Canada. We had also accrued in
Corporate and Other $60 million and $51 million of environmental costs associated with sites no longer in
operation at December 31, 2017 and 2016, respectively. In addition, $15 million and $13 million were
included at both December 31, 2017 and 2016, 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 $96 million at December 31, 2017. The expected future undiscounted payments related to the
portion of the accrued environmental costs that have been discounted are: $12 million in 2018, $10 million in
2019, $5 million in 2020, $10 million in 2021, $3 million in 2022, and $106 million for all future years
after 2022.
99
Note 10—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
5.20% 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 2.31% – 2.75% during 2017
and 1.94% – 2.31% during 2016
Floating rate notes due 2018 at 1.24% – 1.75% during 2017
and 0.69% – 1.24% during 2016
Floating rate notes due 2022 at 1.81% – 2.32% during 2017
and 1.26% – 1.81% during 2016
Industrial Development Bonds due 2017 through 2038 at 0.64% – 1.74% during
2017 and 0.01% – 0.91% during 2016
Marine Terminal Revenue Refunding Bonds due 2031 at 0.64% – 1.74% during
2017 and 0.01% – 0.95% during 2016
Other
Debt at face value
Capitalized leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt
100
Millions of Dollars
2017
2016
150
150
600
100
300
88
500
92
500
575
200
1,549
67
-
2,750
-
645
500
500
505
600
-
-
1,250
750
1,000
500
1,000
500
750
1,000
500
-
-
150
150
600
100
300
88
500
92
500
575
200
1,549
67
297
2,750
1,000
645
500
500
505
600
2,250
500
1,250
750
1,250
500
1,000
500
750
1,000
500
750
1,000
-
1,450
250
500
18
265
23
18,677
774
252
19,703
(2,575)
17,128
250
500
18
265
24
26,175
852
248
27,275
(1,089)
26,186
$
$
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2018 through
2022 are: $2,575 million, $113 million, $97 million, $236 million and $1,602 million, respectively.
We have a revolving credit facility totaling $6.75 billion, expiring in June 2019. 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.
We have two commercial paper programs. The ConocoPhillips $6.25 billion commercial paper program is
available to fund short-term working capital needs. We also have the ConocoPhillips Qatar Funding Ltd.
$500 million commercial paper program, which is used to fund commitments relating to QG3. Commercial
paper maturities are generally limited to 90 days. We had no commercial paper outstanding at December 31,
2017 or 2016, under either the ConocoPhillips or the ConocoPhillips Qatar Funding Ltd. commercial paper
program. We had no direct borrowings or letters of credit issued under the revolving credit facility. 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, 2017.
In 2017, two notes totaling $1,001 million were paid at maturity, including the $1.0 billion 1.05% Notes due
2017. Also in 2017, we prepaid the $1,450 million term loan facility due in 2019.
We also redeemed a total $5.0 billion of debt, described below, incurring $301 million in premiums above
book value, which are reported in the “Other expense” line on our consolidated income statement.
(cid:120) 6.65% Debentures due 2018 with principal of $297 million.
(cid:120) 5.20% Notes due 2018 with principal of $500 million.
(cid:120) 1.5% Notes due 2018 with principal of $750 million.
(cid:120) 5.75% Notes due 2019 with principal of $2.25 billion.
(cid:120) 6.00% Notes due 2020 with principal of $1.0 billion.
(cid:120) 4.20% Notes due 2021 with principal of $1.25 billion (partial redemption of $250 million).
In the fourth quarter of 2017, we gave notice to redeem the following debt instruments totaling $2.25 billion.
(cid:120) 2.2% Notes due 2020 with principal of $500 million.
(cid:120) 4.20% Notes due 2021 with remaining principal of $1.0 billion.
(cid:120) 2.875% Notes due 2021 with principal of $750 million.
The prepayments occurred on January 22, 2018, and we incurred premiums above book value of $75 million.
At both December 31, 2017 and 2016, 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
101
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. Our proportionate interest in the FPS is
29 percent as of December 31, 2017. The net carrying value of the capital lease asset was approximately
$434 million and $540 million as of December 31, 2017 and 2016, 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, 2017 and 2016, accumulated depreciation of
the capital lease asset amounted to approximately $381 million and $268 million, respectively.
At December 31, 2017, future minimum payments due under capital leases were:
2018
2019
2020
2021
2022
Remaining years
Total
Less: portion representing imputed interest
Capital lease obligations
Note 11—Guarantees
Millions
of Dollars
$
$
108
106
106
88
88
487
983
(209)
774
At December 31, 2017, 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, 2017, 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
2017 exchange rates:
(cid:120) We guaranteed APLNG’s performance with regard to a construction contract executed in connection
with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. Our maximum potential
amount of future payments related to this guarantee became immaterial in the second quarter of 2017.
(cid:120) We issued a construction completion guarantee related to the third-party project financing secured by
APLNG. In October 2016, we reached financial completion for Train 1, releasing a portion of our
guarantee. In August 2017, the two-train project finance lenders’ test was completed, releasing the
remaining guarantee.
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(cid:120) During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata
portion of the funds in a project finance reserve account. We estimate the remaining term of this
guarantee is 12 years. Our maximum exposure under this guarantee is approximately $200 million and
may become payable if an enforcement action is commenced by the project finance lenders against
APLNG. At December 31, 2017, the carrying value of this guarantee is approximately $14 million.
(cid:120)
In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales
agreements with remaining terms of up to 24 years. Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $960 million
($1.71 billion in the event of intentional or reckless breach) and would become payable if APLNG fails
to meet its obligations under these agreements and the obligations cannot otherwise be mitigated.
Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-
venturers do not make necessary equity contributions into APLNG.
(cid:120) We have guaranteed the performance of APLNG with regard to certain other contracts executed in
connection with the project’s continued development. The guarantees have remaining terms of up to
28 years or the life of the venture. Our maximum potential amount of future payments related to these
guarantees is approximately $150 million and would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately
$780 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees
of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project
finance reserve accounts. These guarantees have remaining terms of up to 5 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, 2017, 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, 2017, 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 12—Contingencies and Commitments.
In 2012, we completed the separation of our downstream business, creating two independent energy
companies: ConocoPhillips and Phillips 66. 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 $1.31 billion. At
December 31, 2017, the carrying value of this guarantee is approximately $98 million and the remaining term
103
is seven 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 12—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 18—Income Taxes, for additional information
about income tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a material adverse impact on our
consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position
both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future
changes include contingent liabilities recorded for environmental remediation, tax and legal matters.
Estimated future environmental remediation costs are subject to change due to such factors as the uncertain
magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and
the determination of our liability in proportion to that of other responsible parties. Estimated future costs
related to tax and legal matters are subject to change as events evolve and as additional information becomes
available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare
our consolidated financial statements, we record accruals for environmental liabilities based on management’s
best estimates, using all information that is available at the time. We measure estimates and base liabilities on
currently available facts, existing technology, and presently enacted laws and regulations, taking into account
stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior
experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by
the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in
our determination of environmental liabilities, and we accrue them in the period they are both probable and
reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and
several for federal sites and frequently so for 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
104
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 9—Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
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.
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, 2017, we had performance obligations secured by letters of credit of
$338 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.
105
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before
ICSID against The Republic of Ecuador challenging a windfall profits tax and subsequent expropriation of
Blocks 7 and 21. On April 24, 2012, Ecuador filed environmental and infrastructure counterclaims against
Burlington relating to alleged impacts to Blocks 7 and 21. Ecuador also filed the environmental and
infrastructure counterclaims relating to Blocks 7 and 21 in a separate, parallel ICSID arbitration brought by
Perenco Ecuador Limited, Burlington's co-venturer and consortium operator. Perenco and Burlington each
have joint liability for the counterclaims under their joint operating agreements. On December 14, 2012, the
ICSID tribunal issued a decision 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. In February 2017, the
ICSID 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 environmental and infrastructure impacts to Blocks 7 and 21. In
December 2017, Burlington and Ecuador entered into a settlement agreement by which Ecuador agreed to pay
Burlington $337 million in two installments. The first installment of $75 million was timely paid on
December 1, 2017. The second installment of $262 million is to be paid by April 2018. The settlement
includes an offset for the counterclaims decision, of which Burlington is entitled to a $24 million contribution
from Perenco pursuant to the joint operating agreement. The ICSID arbitration between Perenco and Ecuador
remains pending.
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 is being conducted
under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person
tribunal.
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V. in connection
with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. The
arbitral tribunal is in the process of being constituted.
In 2017 and early 2018, cities and/or counties in California and New York have filed lawsuits against oil and
gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged
climate change impacts. ConocoPhillips will be vigorously defending against these lawsuits.
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:
2018—$21 million; 2019—$7 million; 2020—$7 million; 2021—$7 million; 2022—$7 million; and 2023 and
after—$74 million. Total payments under the agreements were $43 million in 2017, $42 million in 2016 and
$27 million in 2015.
Note 13—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.
106
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:
Assets
Prepaid expenses and other current assets
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
$
Millions of Dollars
2017
275
36
282
28
2016
268
44
300
34
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our
consolidated income statement were:
Sales and other operating revenues
Other income
Purchased commodities
Millions of Dollars
2017
2016
2015
$
77
-
(61)
(198)
(1)
161
231
2
(201)
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
Open Position
Long/(Short)
2017
2016
(29)
12
(31)
2
Foreign Currency Exchange Derivatives
We have foreign currency exchange rate risk resulting from international operations. Our foreign currency
exchange derivative activity primarily relates to managing our cash-related 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, and investments in available-for-sale securities. We do not
elect hedge accounting on our foreign currency exchange derivatives.
107
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:
Assets
Prepaid expenses and other current assets
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
$
Millions of Dollars
2017
2016
1
6
-
15
1
-
168
-
In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion
CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.
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
$
13
2017
2016
247
2015
(33)
Millions of Dollars
We had the following net notional position of outstanding foreign currency exchange derivatives:
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy other currencies(1)
Buy U.S. dollar, sell other currencies(2)
Buy British pound, sell other currencies(3)
Sell British pound, buy other currencies(4)
Sell Canadian dollar, buy U.S. dollar
(1)Primarily Canadian dollar.
(2)Primarily British pound.
(3)Primarily Canadian dollar.
(4)Primarily euro and Norwegian krone.
In Millions
Notional Currency
2017
2016
USD
USD
GBP
GBP
CAD
-
-
-
1
1,225
13
25
1,069
51
-
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the various
currency pools we manage. The maturities of these investments may from time to time extend beyond
90 days. The types of financial instruments that we currently invest include:
(cid:120) Time deposits: Interest bearing deposits placed with approved financial institutions.
(cid:120) Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or
government agency purchased at a discount to mature at par.
These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if
the maturities at the time we made the investments were 90 days or less; otherwise, these financial instruments
are included in the “Short-term investments” line on our consolidated balance sheet.
108
Cash
Time deposits
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Commercial paper
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
2017
948
5,004
-
373
-
6,325
$
$
2016
623
2,987
-
-
-
3,610
2017
-
821
-
978
74
1,873
2016
-
39
11
-
-
50
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, government 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, swaps and options, 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, 2017 and December 31, 2016, was $55 million and $42 million,
respectively. For these instruments, no collateral was posted as of December 31, 2017, or December 31, 2016.
If our credit rating had been downgraded below investment grade on December 31, 2017, we would be
required to post $55 million of additional collateral, either with cash or letters of credit.
109
Note 14—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:
(cid:120) Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
(cid:120) Level 2: Inputs other than quoted prices that are directly or indirectly observable.
(cid:120) Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
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. At the end
of the fourth quarter of 2017, our $1,899 million investment in Cenovus Energy was transferred from Level 2 to
Level 1 due to the lapsing of trading restrictions. There were no other material transfers in or out of Level 1
during 2017 or 2016.
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. This also includes our
investment in common shares of Cenovus Energy, which is valued using quotes for shares on the New York
Stock 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):
December 31, 2017
Level 1 Level 2 Level 3
December 31, 2016
Level 1 Level 2 Level 3
Total
Total
Millions of Dollars
Assets
Investment in Cenovus Energy $ 1,899
175
Commodity derivatives
$ 2,074
Total assets
-
106
106
Liabilities
Commodity derivatives
Total liabilities
$
$
158
158
111
111
-
30
30
41
41
1,899
311
2,210
-
194
194
-
96
96
310
310
207
207
105
105
-
22
22
22
22
-
312
312
334
334
110
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.
Millions of Dollars
Gross
Amounts
Recognized
Gross
Amounts
Offset
Net
Amounts
Presented Collateral
Cash
Gross Amounts
without
Right of Setoff
Net
Amounts
December 31, 2017
Assets
Liabilities
December 31, 2016
Assets
Liabilities
$
$
311
310
312
334
186
186
221
221
125
124
91
113
-
7
-
12
4
5
5
12
121
112
86
89
At December 31, 2017, and December 31, 2016, 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 and date of remeasurement for
assets accounted for at fair value on a non-recurring basis:
Millions of Dollars
Fair Value
Measurements Using
Fair Value
Level 1
Inputs
Level 3
Inputs
Before-Tax
Loss
Year ended December 31, 2017
Net PP&E (held for use)
December 31, 2017
Net PP&E (held for sale)
June 30, 2017
December 31, 2017
Cost and equity method investments
June 30, 2017
Year ended December 31, 2016
Net PP&E (held for use)
March 31, 2016
June 30, 2016
December 31, 2016
Net PP&E (held for sale)
September 30, 2016
Cost and equity method investments
December 31, 2016
$
75
-
2,830
113
7,656
217
23
13
217
90
$
2,830
113
75
-
-
154
3,882
78
-
7,656
2,384
-
-
-
217
4
217
23
13
-
86
129
53
29
99
40
Net PP&E (held for use)
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.
111
Net PP&E (held for sale)
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.
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.
During 2017, this included our investment in APLNG, which was written down to its fair value of
$7,656 million, resulting in a before-tax-charge of $2,384 million. For additional information on APLNG, see
Note 5—Investments, Loans and Long-Term Receivables. During 2016, 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.
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
(cid:120) Cash and cash equivalents and short-term investments: The carrying amount reported on the balance
sheet approximates fair value.
(cid:120) Accounts and notes receivable (including long-term and related parties): The carrying amount
reported on the balance sheet approximates fair value. The valuation technique and methods used to
estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans
and advances—related parties.
Investment in Cenovus Energy shares: See Note 6—Investment in Cenovus Energy for a discussion of
the carrying value and fair value of our investment in Cenovus Energy shares.
(cid:120)
(cid:120) Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair
value. The fair value of fixed-rate loan activity is measured using market observable data and is
categorized as Level 2 in the fair value hierarchy. See Note 5—Investments, Loans and Long-Term
Receivables, for additional information.
(cid:120) Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance sheet approximates fair value.
(cid:120) Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a
pricing service that is corroborated by market data; therefore, these liabilities are categorized as
Level 2 in the fair value hierarchy.
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
Investment in Cenovus Energy
Commodity derivatives
Total loans and advances—related parties
Financial liabilities
Total debt, excluding capital leases
Commodity derivatives
$
1,899
125
586
18,929
117
Millions of Dollars
Carrying Amount
Fair Value
2017
2016
2017
-
91
701
1,899
125
586
2016
-
91
701
26,423
101
22,435
117
29,307
101
Commodity Derivatives
At December 31, 2017, commodity derivative assets and liabilities appear net with no obligations to return
cash collateral and $7 million of rights to reclaim cash collateral, respectively. At December 31, 2016,
112
commodity derivative assets and liabilities appear net with no obligations to return cash collateral and
$12 million of rights to reclaim cash collateral, respectively.
Note 15—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
Distributed under benefit plans
End of year
Held in Treasury
Beginning of year
Repurchase of common stock
End of year
Shares
2017
2016
2015
1,782,079,107
3,340,068
1,785,419,175
1,778,226,388
3,852,719
1,782,079,107
1,773,583,368
4,643,020
1,778,226,388
544,809,771
63,502,263
608,312,034
542,230,673
2,579,098
544,809,771
542,230,673
-
542,230,673
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, 2017 or 2016.
Noncontrolling Interests
At December 31, 2017 and 2016, we had $194 million and $252 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
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019.
On March 29, 2017, we announced plans to double our share repurchase program to $6 billion of common
stock through 2019, with $3 billion allocated and purchased in 2017, and the remainder allocated evenly to
2018 and 2019. On February 1, 2018, we announced the acceleration of our previously stated 2018 share
repurchases from $1.5 billion to $2.0 billion, with the remaining balance to be repurchased in 2019.
Repurchase of shares began in November 2016, and totaled 66,081,361 shares at a cost of $3,126 million,
through December 31, 2017.
113
Note 16—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 10—Debt.
At December 31, 2017, future minimum rental payments due under noncancelable leases were:
2018
2019
2020
2021
2022
Remaining years
Total
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
*Amount updated to reflect additional sublease income in 2016.
Millions of Dollars
2017
2016
$
$
264
(20)
244
537
(10)*
527
Millions
of Dollars
278
214
414
126
307
209
1,548
(11)
1,537
2015
432
(9)
423
114
Note 17—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
Plan participant contributions
Benefits paid
Foreign currency exchange rate change
Fair value of plan assets at December 31
Funded Status
Millions of Dollars
Pension Benefits
2017
U.S.
2016
Int’l.
U.S.
Int’l.
Other Benefits
2017
2016
$
$
$
$
$
$
3,416
89
118
-
-
244
(631)
-
-
-
-
3,236
3,445
77
103
2
-
52
(117)
-
-
-
283
3,845
3,772
108
133
-
-
247
(872)
14
-
14
-
3,416
3,321
76
120
3
-
466
(148)
10
(46)
1
(358)
3,445
3,076
3,404
3,246
3,067
2,081
336
755
-
(631)
-
2,541
(695)
3,068
313
114
2
(117)
267
3,647
(198)
2,606
133
214
-
(872)
-
2,081
(1,335)
3,063
397
125
3
(148)
(372)
3,068
(377)
286
2
9
23
-
12
(68)
-
-
-
1
265
-
-
45
23
(68)
-
-
(265)
352
2
13
24
(27)
(14)
(68)
3
-
-
1
286
-
-
44
24
(68)
-
-
(286)
115
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
Current liabilities
Noncurrent liabilities
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
Discount rate
Expected return on plan assets
Rate of compensation increase
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
$
$
-
(38)
(657)
(695)
205
(4)
(399)
(198)
-
(101)
(1,234)
(1,335)
164
(7)
(534)
(377)
-
(45)
(220)
(265)
-
(44)
(242)
(286)
3.55 %
4.00
2.80
3.75
3.95
4.00
3.00
3.85
3.30
-
3.60
-
3.80 %
6.55
4.00
3.00
5.05
3.85
3.90
7.00
4.00
3.95
5.45
4.05
3.60
-
-
3.75
-
-
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:
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost (credit)
$
588
-
358
(16)
748
4
479
(20)
(12)
(249)
(27)
(285)
116
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
Amortization of (gain) loss included in
income (loss)*
Net change during the period
Prior service credit (cost) arising during the
period
Amortization of prior service cost (credit)
included in income (loss)
Net change during the period
*Includes settlement losses recognized in 2017 and 2016.
$
$
$
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
$
(40)
71
(263)
(232)
(12)
200
160
50
121
288
25
26
(206)
(3)
(15)
14
(5)
9
-
4
4
2
(6)
(4)
-
5
5
(4)
(6)
(10)
-
27
(36)
(36)
(34)
(7)
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.
Included in accumulated other comprehensive loss at December 31, 2017, were the following before-tax
amounts that are expected to be amortized into net periodic benefit cost during 2018:
Millions of Dollars
Pension
Benefits
U.S.
Int’l.
Other
Benefits
Unrecognized net actuarial (gain) loss
Unrecognized prior service credit
$
59
-
36
(5)
(1)
(34)
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 $5,634 million,
$5,226 million, and $5,113 million, respectively, at December 31, 2017, and $5,498 million, $5,145 million,
and $4,208 million, respectively, at December 31, 2016.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and
the accumulated benefit obligation were $578 million and $503 million, respectively, at December 31, 2017,
and were $586 million and $496 million, respectively, at December 31, 2016.
117
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
Millions of Dollars
2017
Pension Benefits
2016
Other Benefits
2015
2017
2016
2015
U.S.
Int’l.
U.S.
Int’l. U.S.
Int’l.
$
89
118
77
103
108
133
76
120
138
161
124
135
(132)
(158)
(149)
(147)
(201) (164)
2
9
-
2
13
-
4
22
-
4
(6)
5
(6)
6
(7)
(36)
(34)
(17)
69
131
-
279
$
50
-
-
66
86
202
14
399
26
-
-
69
115
197
35
451
82
7
(4)
173
(3)
-
-
(28)
(2)
-
1
(20)
2
-
2
13
Components of Net
Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan
assets
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 $131 million in 2017, $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 6.25 percent in
2018 that declines to 5 percent by 2023. The measurement of the U.S. post-65 retiree medical accumulated
postretirement benefit obligation assumes an ultimate health care cost trend rate of 5 percent achieved in 2018.
A one-percentage-point change in the assumed health care cost trend rate would be immaterial to
ConocoPhillips.
118
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 43 percent equity
securities, 50 percent debt securities, 6 percent real estate and 1 percent other. 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, 2017 and 2016.
(cid:120) Fair values of equity securities and government debt securities categorized in Level 1 are
primarily based on quoted market prices in active markets for identical assets and liabilities.
(cid:120) Fair values of corporate debt securities, agency and mortgage-backed securities and government
debt securities categorized in Level 2 are estimated using recently executed transactions and
quoted market prices for similar assets and liabilities in active markets and for identical assets and
liabilities in markets that are not active. If there have been no market transactions in a particular
fixed income security, its fair value is calculated by pricing models that benchmark the security
against other securities with actual market prices. When observable quoted market prices are not
available, fair value is based on pricing models that use something other than actual market prices
(e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar
securities), and these securities are categorized in Level 3 of the fair value hierarchy.
(cid:120) Fair values of investments in common/collective trusts are determined by the issuer of each fund
based on the fair value of the underlying assets.
(cid:120) Fair values of mutual funds are based on quoted market prices, which represent the net asset value
of shares held.
(cid:120) Time deposits are valued at cost, which approximates fair value.
(cid:120) Cash is valued at cost, which approximates fair value. Fair values of international cash
equivalents categorized in Level 2 are valued using observable yield curves, discounting and
interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at
the measurement date are categorized as Level 2.
(cid:120) Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market
prices. For other derivatives classified in Level 2, the values are generally calculated from pricing
models with market input parameters from third-party sources.
(cid:120) Fair values of insurance contracts are valued at the present value of the future benefit payments
owed by the insurance company to the plans’ participants.
(cid:120) Fair values of real estate investments are valued using real estate valuation techniques and other
methods that include reference to third-party sources and sales comparables where available.
(cid:120) A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity
contract, which is calculated as the market value of investments held under this contract, less the
accumulated benefit obligation covered by the contract. The participating interest is classified as
Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted
market prices, recently executed transactions, and an actuarial present value computation for
contract obligations. At December 31, 2017, the participating interest in the annuity contract was
valued at $99 million and consisted of $265 million in debt securities, less $166 million for the
accumulated benefit obligation covered by the contract. At December 31, 2016, the participating
interest in the annuity contract was valued at $121 million and consisted of $288 million in debt
securities, less $167 million for the accumulated benefit obligation covered by the contract. The
net change from 2016 to 2017 is due to a decrease in the fair value of the underlying investments
of $23 million offset by a decrease in the present value of the contract obligation of $1 million.
The participating interest is not available for meeting general pension benefit obligations in the
near term. No future company contributions are required and no new benefits are being accrued
under this insurance annuity contract.
119
The fair values of our pension plan assets at December 31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1 Level 2
Level 3
Total
Level 1 Level 2
Level 3
Total
$
2017
Equity securities
U.S.
International
Common/collective trusts
Mutual funds
Debt securities
Government
Corporate
Common/collective trusts
Mutual funds
Cash and cash equivalents
Time deposits
Derivatives
Real estate
Total in fair value hierarchy
$
161
178
-
146
-
-
-
-
-
-
-
-
485
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Corporate
Agency and mortgage-backed securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
$
-
-
-
-
-
-
485
$
-
-
-
-
-
2
-
-
-
-
-
-
2
-
-
-
-
-
-
2
14
-
-
-
-
-
-
-
-
-
-
-
14
-
-
-
-
-
-
14
175
178
-
146
-
2
-
-
-
-
-
-
501
440
315
-
292
902
-
-
144
111
3
5
-
2,212
805
-
-
-
1,042
17
74
2,439
-
-
-
-
-
2,212
-
-
183
165
-
-
648
-
-
-
-
-
996
-
-
-
-
-
-
996
-
-
-
-
-
-
-
-
-
-
-
123
123
-
-
-
-
-
-
123
440
315
183
457
902
-
648
144
111
3
5
123
3,331
-
172
15
-
24
94
3,636
*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 $99 million and net receivables related to security transactions
of $14 million.
120
The fair values of our pension plan assets at December 31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1 Level 2
Level 3
Total
Level 1 Level 2
Level 3
Total
$
2016
Equity securities
U.S.
International
Common/collective trusts
Mutual funds
Debt securities
Government
Corporate
Common/collective trusts
Mutual funds
Cash and cash equivalents
Derivatives
Real estate
Total in fair value hierarchy
$
632
342
-
62
-
-
-
-
-
-
-
1,036
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Corporate
Agency and mortgage-backed securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
$
-
-
-
-
-
-
1,036
$
-
-
-
-
38
54
-
-
-
-
-
92
-
-
-
-
-
-
92
14
-
-
-
-
3
-
-
-
-
-
17
-
-
-
-
-
-
17
646
342
-
62
38
57
-
-
-
-
-
1,145
628
428
-
268
470
-
-
137
48
18
-
1,997
410
-
-
-
312
36
69
1,972
-
-
-
-
-
1,997
-
-
156
139
-
-
385
-
-
-
-
680
-
-
-
-
-
-
680
-
-
-
-
-
-
-
-
-
-
111
111
-
-
-
-
-
-
111
628
428
156
407
470
-
385
137
48
18
111
2,788
-
155
27
-
11
76
3,057
*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.
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 2018, we expect to contribute approximately $80 million to our domestic nonqualified pension and
postretirement benefit plans and $130 million to our international qualified and nonqualified pension and postretirement benefit
plans.
121
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:
Millions of Dollars
Pension
Benefits
U.S.
Int’l.
Other
Benefits
2018
2019
2020
2021
2022
2023–2027
$
383
302
290
286
291
1,247
122
141
135
144
144
780
40
37
34
31
28
91
Severance Accrual
As a result of selling our 50 percent nonoperated interest in the FCCL Partnership and the majority of our
western Canada gas assets, as well as our interest in the San Juan Basin, a reduction in our overall employee
workforce occurred during 2017. Severance accruals of $65 million were recorded in 2017. The following
table summarizes our severance accrual activity for the year ended December 31, 2017:
Balance at December 31, 2016
Accruals
Benefit payments
Foreign currency translation adjustments
Balance at December 31, 2017
Millions of Dollars
$
$
80
65
(93)
1
53
Of the remaining balance at December 31, 2017, $30 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 options. 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 $51 million in 2017, $58 million in 2016, and $109 million in 2015.
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 $35 million in 2017, $44 million in 2016, and $55 million in 2015.
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
122
of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards
granted. Awards may be granted in the form of, but not limited to, stock options, restricted stock units and
performance share units to employees and non-employee 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 loss and the associated
tax benefit for the years ended December 31 were as follows:
Compensation cost
Tax benefit
Millions of Dollars
2017
227
76
$
2016
272
92
2015
362
123
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)
2017
2016
2015
2.24 %
4.00 %
28.12 %
6.39
1.55
4.00
26.80
6.37
1.79
4.00
23.32
5.79
There were no ranges in the assumptions used to determine the fair market values of our options granted over
the past three years.
We believe our historical volatility for periods prior to the 2012 separation of our Downstream businesses is no
longer relevant in estimating expected volatility. For 2015 through 2017, 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.
123
The following summarizes our stock option activity for the year ended December 31, 2017:
Outstanding at December 31, 2016
Granted
Exercised
Forfeited
Expired or cancelled
Outstanding at December 31, 2017
Vested at December 31, 2017
Exercisable at December 31, 2017
Options
23,712,112 $
2,670,200
(360,396)
(50,696)
(1,248,417)
24,722,803 $
23,424,010 $
18,074,088 $
Weighted-
Weighted-
Average
Exercise Price
Average Millions of Dollars
Aggregate
Intrinsic Value
Grant Date
Fair Value
$
9.18
52.14
49.76
37.24
48.55
50.61
52.18
52.52
54.34
$
$
$
$
128
4
177
162
101
The weighted-average remaining contractual term of outstanding options, vested options and exercisable
options at December 31, 2017, was 5.52 years, 5.36 years and 4.50 years, respectively. The weighted-average
grant date fair value of stock option awards granted during 2016 and 2015 was $5.39 and $9.54, respectively.
The aggregate intrinsic value of options exercised was zero in 2016 and $10 million in 2015.
During 2017, we received $13 million in cash and realized a tax benefit of $12 million from the exercise of
options. At December 31, 2017, the remaining unrecognized compensation expense from unvested options was
$5 million, which will be recognized over a weighted-average period of 1.33 years, the longest period being
2.12 years.
Beginning in 2018, stock option grants will be discontinued and replaced with three-year, time-vested
restricted stock units which will be cash-settled.
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.
124
The following summarizes our stock unit activity for the year ended December 31, 2017:
Outstanding at December 31, 2016
Granted
Forfeited
Issued
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Stock Units
8,507,504
3,011,903
(372,871)
(3,319,684)
7,826,852
5,396,027
Weighted-Average Millions of Dollars
Total Fair Value
Grant Date Fair Value
$
$
$
48.65
48.77
45.99
45.75
45.58
$
159
At December 31, 2017, the remaining unrecognized compensation cost from the unvested units was
$93 million, which will be recognized over a weighted-average period of 1.67 years, the longest period being
2.75 years. The weighted-average grant date fair value of stock unit awards granted during 2016 and 2015 was
$32.15 and $65.40, respectively. The total fair value of stock units issued during 2016 and 2015 was
$191 million and $316 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.
125
The following summarizes our stock-settled Performance Share Program activity for the year ended
December 31, 2017:
Outstanding at December 31, 2016
Granted
Issued
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Stock Units
3,889,524
30,953
(1,167,012)
2,753,465
67,083
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
$
$
51.93
49.76
50.79
48.17
$
57
At December 31, 2017, the remaining unrecognized compensation cost from unvested stock-settled
performance share awards was $1 million, which will be recognized over a weighted-average period of
2.00 years, the longest period being 3.00 years. The weighted-average grant date fair value of stock-settled
PSUs granted during 2016 and 2015 was $33.13 and $69.25, respectively. The total fair value of stock-settled
PSUs issued during 2016 and 2015 was $17 million and $25 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 at 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.
The following summarizes our cash-settled Performance Share Program activity for the year ended
December 31, 2017:
Outstanding at December 31, 2016
Granted
Settled
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
$
$
50.39
49.76
55.19
55.19
$
24
Stock Units
1,274,762
456,909
(517,138)
1,214,533
122,228
126
At December 31, 2017, the remaining unrecognized compensation cost from unvested cash-settled
performance share awards was $2 million, which will be recognized over a weighted-average period of
1.64 years, the longest period being 2.13 years. The weighted-average grant date fair value of cash-settled
PSUs granted during 2016 and 2015 was $33.13 and $69.25, respectively. The total fair value of cash-settled
performance share awards settled during 2016 and 2015 was $31 million and $6 million, 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 terminated at the end of the three-year performance
period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the
initial target PSU awards terminated at the end of the three-year performance period and were settled after the
performance period 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 as part of our non-employee director compensation program for current and
former members of the company’s Board of Directors or as part of an executive 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, 2017:
Outstanding at December 31, 2016
Granted
Cancelled
Issued
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
33.16
48.87
21.37
$
32.66
$
4
Stock Units
1,317,964
87,980
(24,486)
(80,418)
1,301,040
-
At December 31, 2017, 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 2016 and 2015 was $40.36 and $58.66, respectively. The total fair value of awards issued
during 2016 and 2015 was $2 million and $3 million, respectively.
127
Note 18—Income Taxes
Income tax benefits included in net loss were:
Income Taxes
Federal
Current
Deferred
Foreign
Current
Deferred
State and local
Current
Deferred
Millions of Dollars
2017
2016
2015
79
(3,046)
(9)
(1,634)
1,729
(510)
51
(125)
(1,822)
393
(519)
(135)
(67)
(1,971)
(718)
(1,443)
745
(1,315)
8
(145)
(2,868)
$
$
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
Investments in joint ventures
Inventory
Deferred state income tax
Other
Total deferred tax liabilities
Deferred Tax Assets
Benefit plan accruals
Asset retirement obligations and accrued environmental costs
Investments in joint ventures
Other financial accruals and deferrals
Loss and credit carryforwards
Other
Total deferred tax assets
Less: valuation allowance
Net deferred tax assets
Net deferred tax liabilities
Millions of Dollars
2017
2016
$
$
9,692
-
61
178
464
10,395
786
3,060
57
166
2,310
152
6,531
(1,254)
5,277
5,118
15,099
933
36
203
486
16,757
1,280
3,514
-
317
3,522
250
8,883
(675)
8,208
8,549
At December 31, 2017, noncurrent assets and liabilities included deferred taxes of $164 million and
$5,282 million, respectively. At December 31, 2016, noncurrent assets and liabilities included deferred taxes
of $400 million and $8,949 million, respectively.
128
At December 31, 2017, the components of our loss and credit carryforwards before and after consideration of
the applicable valuation allowances are:
U.S. foreign tax credits
U.S. general business credits
State net operating losses and tax credits
Foreign net operating losses and tax credits
Millions of Dollars
Gross Deferred
Tax Asset
Net Deferred Expiration of
Tax Asset After Net Deferred
Tax Asset
Valuation Allowance
$
$
856
227
420
807
2,310
567
227
-
786
1,580
2025-2027
2036-2037
Post 2025
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely
than not, be realized. During 2017, valuation allowances increased a total of $579 million. This increase
primarily relates to the expected realization of certain deferred tax assets, including foreign tax credits; U.S.
tax basis associated with foreign assets; and state net operating losses and tax credits not expected to be
realized. Based on our historical taxable income, expectations for the future, and available tax-planning
strategies, management expects deferred tax assets, net of valuation allowance, will primarily be realized as
offsets to reversing deferred tax liabilities.
At December 31, 2017, unremitted income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $2,600 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. The estimated amount of additional tax that would be payable on this income if distributed is
approximately $130 million.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2017,
2016 and 2015:
Balance at January 1
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Lapse of statute
Balance at December 31
Millions of Dollars
2017
381
612
109
(129)
(5)
(86)
882
$
$
2016
459
32
19
(118)
(9)
(2)
381
2015
442
54
4
(37)
(4)
-
459
Included in the balance of unrecognized tax benefits for 2017, 2016 and 2015 were $882 million, $359 million
and $354 million, respectively, which, if recognized, would impact our effective tax rate. The balance of
unrecognized tax benefits increased in 2017 mainly due to the recognition of a U.S. worthless securities
deduction that we do not believe will generate a cash tax benefit.
At December 31, 2017, 2016 and 2015, accrued liabilities for interest and penalties totaled $54 million,
$54 million and $79 million, respectively, net of accrued income taxes. Interest and penalties resulted in no
impact to earnings in 2017, a benefit to earnings of $18 million in 2016, and a reduction to earnings of
$11 million in 2015.
129
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 (2016). 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. 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) before income taxes, with a reconciliation of tax at the federal
statutory rate with the provision for income taxes, were:
Loss before income taxes
United States
Foreign
Federal statutory income tax
Non-U.S. effective tax rates
Impact of U.S. tax legislation
Canada disposition
Recovery of outside basis
Adjustment to tax reserves
APLNG impairment
State income tax
Enhanced oil recovery credit
U.K. rate change
Canada rate change
U.S. fair value election
Other
Millions of Dollars
2017
2016
Percent of Pre-Tax Income (Loss)
2015
2017
2016
2015
$
$
$
$
(5,250)
2,635
(2,615)
(915)
625
(852)
(1,277)
(962)
881
834
(84)
(68)
-
-
-
(4)
(1,822)
(4,410)
(1,120)
(5,530)
(1,936)
361
-
-
(60)
55
-
(122)
(62)
(161)
-
-
(46)
(1,971)
(4,150)
(3,089)
(7,239)
(2,534)
301
-
-
(491)
42
525
(85)
-
(555)
129
(185)
(15)
(2,868)
200.8 %
(100.8)
100.0 %
79.7
20.3
100.0
57.3
42.7
100.0
35.0 %
(23.9)
32.6
48.8
36.8
(33.7)
(31.9)
3.2
2.6
-
-
-
0.2
69.7 %
35.0
(6.5)
-
-
1.1
(1.0)
-
2.2
1.1
2.9
-
-
0.8
35.6
35.0
(4.2)
-
-
6.8
(0.6)
(7.3)
1.2
-
7.7
(1.8)
2.6
0.2
39.6
The increase in the effective tax rate for 2017 was primarily due to the impact of the Tax Cuts and Jobs Act
(Tax Legislation) and the impact of the Canada disposition, partially offset by the impact of the APLNG
impairment and our mix of income among taxing jurisdictions.
The Tax Legislation, enacted on December 22, 2017, reduces the U.S. federal corporate tax rate from
35 percent to 21 percent, requires companies to pay a one-time transition tax on earnings of certain foreign
subsidiaries that were previously tax deferred and creates new taxes on certain foreign-sourced earnings. At
December 31, 2017, we have not completed our accounting for the tax effects of enactment of the Tax
Legislation; however, as described below, we have made a reasonable estimate of the effects on our existing
deferred tax balances and the one-time transition tax and recorded a provisional tax benefit of $852 million.
Provisional Amount—Deferred tax assets and liabilities
In the fourth quarter of 2017, we remeasured certain U.S. deferred tax assets and liabilities based on the
rates at which they are expected to reverse in the future, which is generally 21 percent. However, we are
still analyzing certain aspects of the Tax Legislation and refining our calculations, which could potentially
affect the measurement of these balances or potentially give rise to new deferred tax amounts. The
provisional amount recorded related to the remeasurement of our U.S. deferred tax balance was a tax
benefit of $908 million.
130
Provisional Amount—Foreign tax effects
The one-time transition tax is based on our total post-1986 earnings and profits which we have previously
deferred from U.S. income taxes. We reasonably estimate that we will not incur a one-time transition tax.
This assumption may change when we finalize the calculation of post-1986 foreign earnings and profits,
previously deferred from U.S. federal taxation, and finalize the amounts held in cash or other specified
assets. As a result of the Tax Legislation, we have removed the indefinite reinvestment assertion on one of
our foreign subsidiaries and recorded a tax expense of $56 million in the fourth quarter of 2017.
Our effective tax rate in 2017 was favorably impacted by a tax benefit of $1,277 million related to the Canada
disposition. This tax benefit was primarily associated with a deferred tax recovery related to the Canadian
capital gains exclusion component of the 2017 Canada disposition and the recognition of previously
unrealizable Canadian capital asset tax basis. The Canada disposition, along with the associated restructuring
of our Canadian operations, may generate an additional tax benefit of $822 million. However, since we
believe it is not likely we will receive a corresponding cash tax savings, this $822 million benefit has been
offset by a full tax reserve. See Note 4—Assets Held for Sale, Sold or Acquired for additional information on
our Canada disposition.
The impairment of our APLNG investment in the second quarter of 2017 did not generate a tax benefit. See
the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment.
The decrease in the effective tax rate for 2016 was primarily due to our mix of income among taxing
jurisdictions, reduced net tax benefit from the tax law changes discussed below, and the absence of a tax
benefit associated with electing the fair market value method of apportioning interest expense for prior years.
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, we recorded a
$161 million net tax benefit related to the remeasurement of our U.K. deferred tax balance in 2016.
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, we recorded a
$555 million net tax benefit related to the remeasurement of our U.K. deferred tax balance in 2015.
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, we recorded a $129 million net tax expense related
to the remeasurement of our Canadian deferred tax balance in 2015.
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, we recorded a $185 million tax benefit associated with these refund
claims in 2015.
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 2017, 2016 and 2015 the amount of the tax benefit was $962 million, $60 million and
$491 million, respectively.
131
Note 19—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the equity section of the balance sheet included:
Millions of Dollars
Net
Unrealized
Loss on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
-
-
-
-
-
(58)
(58)
(641)
(5,163)
(5,804)
158
(5,646)
586
(5,060)
(1,902)
(4,345)
(6,247)
54
(6,193)
675
(5,518)
Defined
Benefit Plans
$
$
(1,261)
818
(443)
(104)
(547)
147
(400)
December 31, 2014
Other comprehensive income (loss)
December 31, 2015
Other comprehensive income (loss)
December 31, 2016
Other comprehensive income (loss)
December 31, 2017
There were no items within accumulated other comprehensive 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
Above amounts are included in the computation of net periodic benefit cost and
are presented net of tax expense of:
See Note 17—Employee Benefit Plans, for additional information.
Note 20—Cash Flow Information
Noncash Investing 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
Millions of Dollars
2017
135
74
$
$
2016
179
95
Millions of Dollars
2017
2016
2015
(37)
(1,017)
402
1,163
1,168
1,151
(318) *
920
523 *
(6,617)
4,827
(1,790)
(1,753)
1,702
(51)
-
-
-
$
$
$
$
*Net of $585 million and $642 million in 2016 and 2015, respectively, related to refunds received from the Internal Revenue Service.
132
$
$
$
$
$
$
$
$
Millions of Dollars
2017
2016
2015
1,114
103
1,217
(119)
1,098
112
417
529
100
1,279
123
1,402
(157)
1,245
57
198
255
116
1,130
84
1,214
(294)
920
45
80
125
222
1,058
1,139
1,181
-
-
3
7
23
1
(3)
31
-
-
1
(7)
(9)
7
(18)
(26)
-
-
-
(22)
(78)
(9)
45
(64)
Millions of Dollars
2017
2016
4,491
3,896
$ 102,044 119,970
5,150
6,286
110,431 131,406
(73,075)
58,331
(64,748)
$ 45,683
Note 21—Other Financial Information
Interest and Debt Expense
Incurred
Debt
Other
Capitalized
Expensed
Other Income
Interest income
Other, net
Research and Development Expenditures—expensed
Shipping and Handling Costs*
*Amounts included in production and operating expenses.
Foreign Currency Transaction (Gains) Losses—after-tax
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Properties, Plants and Equipment
Proved properties
Unproved properties
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
Net properties, plants and equipment
133
Note 22—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:
Millions of Dollars
2017
2016
2015
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 5—Investments, Loans and Long-Term Receivables, for additional
information on loans to affiliated companies.
133
101
63
(12)
107
99
59
(13)
118
97
62
(9)
$
The table above includes transactions with the FCCL Partnership through the date of the sale. See Note 5—
Investments, Loans and Long-Term Receivables, for additional information.
Note 23—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.
Corporate and Other represents costs not directly associated with an operating segment, such as most interest
expense, premiums on early retirement of debt, corporate overhead and certain technology activities, including
licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.
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.
134
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Alaska
Lower 48
Intersegment eliminations
Lower 48
Canada
Intersegment eliminations
Canada
Europe and North Africa
Intersegment eliminations
Europe and North Africa
Asia Pacific and Middle East
Intersegment eliminations
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated sales and other operating revenues
Depreciation, Depletion, Amortization and Impairments
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated depreciation, depletion, amortization and impairments
Millions of Dollars
2017
2016
$
$
$
$
4,224
12,968
(4)
12,964
3,178
(559)
2,619
5,181
-
5,181
4,014
-
4,014
-
104
29,106
1,026
6,693
461
1,313
3,819
-
134
13,446
3,681
10,719
(17)
10,702
2,192
(218)
1,974
3,462
-
3,462
3,705
-
3,705
-
169
23,693
868
4,358
975
1,253
1,606
1
140
9,201
2015
4,351
11,976
(63)
11,913
2,454
(318)
2,136
6,110
(4)
6,106
4,746
(1)
4,745
1
312
29,564
690
4,227
788
2,565
2,981
-
107
11,358
In 2017, sales by our Lower 48, Alaska and Canada segments to a certain refining company accounted for
approximately $3 billion or 11 percent of our total consolidated sales and other operating revenues.
135
Equity in Earnings of Affiliates
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated equity in earnings of affiliates
Income Taxes
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated income taxes
Net Income (Loss) Attributable to ConocoPhillips
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated net loss attributable to ConocoPhillips
Investments In and Advances To Affiliates
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated investments in and advances to affiliates
Millions of Dollars
2017
2016
2015
$
$
$
$
$
$
$
$
7
5
197
10
553
-
-
772
(689)
(2,453)
(616)
1,165
351
21
399
(1,822)
1,466
(2,371)
2,564
553
(1,098)
167
(2,136)
(855)
56
402
-
55
9,077
-
-
9,590
9
(6)
89
22
(51)
-
(11)
52
(59)
(1,328)
(383)
(46)
306
(40)
(421)
(1,971)
319
(2,257)
(935)
394
209
(16)
(1,329)
(3,615)
58
426
8,784
62
11,611
-
4
20,945
4
(5)
78
23
550
8
(3)
655
(71)
(1,119)
(223)
(854)
467
(456)
(612)
(2,868)
4
(1,932)
(1,044)
409
(463)
(593)
(809)
(4,428)
61
455
8,165
70
11,780
-
15
20,546
136
Total Assets
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated total assets
Capital Expenditures and Investments
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated capital expenditures and investments
Interest Income and Expense
Interest income
Corporate
Lower 48
Europe and North Africa
Asia Pacific and Middle East
Other International
Interest and debt expense
Corporate
Sales and Other Operating Revenues by Product
Crude oil
Natural gas
Natural gas liquids
Other*
Consolidated sales and other operating revenues by product
*Includes LNG and bitumen.
Millions of Dollars
2017
2016
12,108
14,632
6,214
11,870
16,985
97
11,456
73,362
815
2,136
202
872
482
21
63
4,591
101
-
2
9
-
12,314
22,673
17,548
11,727
20,451
97
4,962
89,772
883
1,262
698
1,020
838
104
64
4,869
47
-
2
8
-
2015
12,555
26,932
17,221
13,703
22,318
282
4,473
97,484
1,352
3,765
1,255
1,573
1,812
173
120
10,050
36
-
2
6
1
1,098
1,245
920
13,260
10,773
1,102
3,971
29,106
10,801
9,401
837
2,654
23,693
12,830
11,888
952
3,894
29,564
$
$
$
$
$
$
$
$
137
Geographic Information
Sales and Other Operating Revenues(1)
Long-Lived Assets(2)
2017
2016
2015
2017
2016
2015
Millions of Dollars
$
United States
Australia(3)
Canada
China
Indonesia
Malaysia
Norway
United Kingdom
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.
14,400
1,353
1,974
551
938
735
1,645
1,816
281
23,693
16,284
2,127
2,136
782
1,165
598
2,107
4,005
360
29,564
17,204
1,448
2,619
712
757
1,103
2,348
2,248
667
29,106
32,949
12,259
16,846
1,372
856
3,323
6,228
3,209
2,234
79,276
23,623
9,657
5,613
1,275
758
2,736
6,154
3,335
2,122
55,273
$
37,445
12,788
16,766
1,647
1,191
3,599
6,933
4,154
2,469
86,992
Note 24—New Accounting Standards
In May 2014, the FASB issued Accounting Standards Update (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 will 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. The impact to our financial statements is immaterial but
will include a cumulative effect reduction of $220 million to retained earnings from initially applying the new
138
revenue standard relating to licensing revenues previously recognized. Under the new revenue standard
licensing revenue will be recognized when the customer can utilize and benefit from their right to use the
license.
In January 2016, the FASB issued ASU No. 2016-01, “Recognition and Measurement of Financial Assets and
Financial Liabilities” (ASU No. 2016-01), to meet its objective of providing more decision-useful information
about financial instruments. The ASU, among other things, requires entities to record the changes in fair value
of equity investments, other than investments accounted for using the equity method, within net income.
Under this ASU, entities will no longer be able to recognize unrealized holding gains and losses on available-
for-sale securities in other comprehensive income. The ASU also requires additional disclosures relating to
fair value measurement categories for financial assets and liabilities and eliminates certain disclosure
requirements related to financial instruments measured at amortized cost. ASU No. 2016-01 is effective for
interim and annual periods beginning after December 15, 2017, and the ASU should be adopted using a
cumulative-effect adjustment to retained earnings as of the date of adoption.
Upon adoption of the standard, we will make a cumulative-effect adjustment to reclassify the accumulated
unrealized holding gains and losses of $58 million related to our investment in Cenovus Energy from other
comprehensive income to retained earnings. From January 1, 2018, we will begin reporting the changes in the
fair value of our investment within net income. For additional information on our investment in Cenovus
Energy, see Note 6—Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 19—
Accumulated Other Comprehensive Loss.
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. In January 2018, ASU No. 2016-02
was amended by the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to
Topic 842.” We plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, and continue to
evaluate the ASU to determine the impact of adoption on our consolidated financial statements and
disclosures, accounting policies and systems, business processes, and internal controls. We also continue to
monitor proposals issued by the FASB to clarify the ASU and certain industry implementation issues. While
our evaluation of ASU No. 2016-02 and related implementation activities are ongoing, 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.
139
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, 2017,
approximately 8 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East
geographic reporting area, and 5 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.
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.
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and
reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our
140
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, geoscientists,
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 2017, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2017, 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, 2017, 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.
141
Proved Reserves
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Equity affiliates
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Total company
End of 2014
End of 2015
End of 2016
End of 2017
Lower
48
Alaska
Total
Other
Asia Pacific/
U.S. Canada Europe Middle East Africa Areas
Total
Crude Oil
Millions of Barrels
1,063
(115)
4
-
20
(57)
-
915
(57)
6
-
33
(60)
-
837
113
6
-
41
(60)
-
937
676
(69)
4
-
57
(78)
(2)
588
(93)
3
-
79
(71)
-
506
65
-
-
210
(64)
(10)
707
1,739
(184)
8
-
77
(135)
(2)
1,503
(150)
9
-
112
(131)
-
1,343
178
6
-
251
(124)
(10)
1,644
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
24
-
1
-
1
(4)
(8)
14
3
-
-
-
(3)
(1)
13
1
-
-
-
(1)
(12)
1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
411
(21)
-
-
-
(44)
-
346
-
-
-
-
(43)
-
303
38
-
-
-
(45)
-
296
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
227
(29)
31
-
7
(33)
-
203
6
7
-
7
(35)
(3)
185
32
-
-
2
(34)
-
185
98
-
-
-
-
(5)
-
93
-
-
-
-
(5)
-
88
-
-
-
-
(5)
-
83
204
-
-
-
-
-
-
204
-
-
-
-
(1)
-
203
-
-
-
-
(7)
-
196
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,605
(234)
40
-
85
(216)
(10)
2,270
(141)
16
-
119
(213)
(4)
2,047
249
6
-
253
(211)
(22)
2,322
5
-
-
-
-
(1)
(4)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
103
-
-
-
-
(6)
(4)
93
-
-
-
-
(5)
-
88
-
-
-
-
(5)
-
83
1,063
915
837
937
676
588
506
707
1,739
1,503
1,343
1,644
24
14
13
1
411
346
303
296
325
296
273
268
204
204
203
196
5
-
-
-
2,708
2,363
2,135
2,405
142
Years Ended
December 31
Developed
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Undeveloped
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Alaska
Lower
48
Total
U.S. Canada
Europe
Asia Pacific/
Middle East
Africa
Other
Areas
Total
Crude Oil
Millions of Barrels
950
819
747
828
-
-
-
-
113
96
90
109
-
-
-
-
313
283
256
315
1,263
1,102
1,003
1,143
-
-
-
-
363
305
250
392
-
-
-
-
-
-
-
-
476
401
340
501
-
-
-
-
23
13
13
1
-
-
-
-
1
1
-
-
-
-
-
-
237
200
184
190
-
-
-
-
174
146
119
106
-
-
-
-
142
139
106
121
98
93
88
83
85
64
79
64
-
-
-
-
199
204
203
196
-
-
-
-
5
-
-
-
-
-
-
-
-
-
-
-
5
-
-
-
-
-
-
-
-
-
-
-
1,864
1,658
1,509
1,651
103
93
88
83
741
612
538
671
-
-
-
-
Notable changes in proved crude oil reserves in the three years ended December 31, 2017, included:
(cid:120) Revisions: In 2017, revisions in Alaska, Lower 48, Europe and Asia Pacific/Middle East were primarily due to higher
prices. In 2016, revisions in Lower 48 and Alaska were primarily due to lower prices. In 2015, revisions in Alaska,
Lower 48 and Asia Pacific/Middle East were primarily due to lower prices.
(cid:120) Extensions and discoveries: In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling
success in the Permian Unconventional, Eagle Ford and Bakken. In 2016, extensions and discoveries in Alaska were
primarily due to drilling success in the Western North Slope, and extensions and discoveries in Lower 48 were
primarily due to continued drilling success in Eagle Ford and Bakken.
(cid:120)
Sales: In 2017, Canada sales were due to the disposition of a majority of our western Canada assets.
143
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Equity affiliates
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Total company
End of 2014
End of 2015
End of 2016
End of 2017
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
120
(1)
-
-
-
(5)
-
114
(3)
-
-
-
(4)
-
107
4
-
-
-
(5)
-
106
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
440
(84)
-
-
10
(36)
(9)
321
(29)
-
-
18
(32)
-
278
29
-
-
71
(24)
(130)
224
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
560
(85)
-
-
10
(41)
(9)
435
(32)
-
-
18
(36)
-
385
33
-
-
71
(29)
(130)
330
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
65
(10)
-
-
2
(9)
(3)
45
9
-
-
2
(8)
-
48
-
-
-
-
(3)
(44)
1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
24
(1)
-
-
-
(3)
-
20
2
-
-
-
(3)
-
19
2
-
-
-
(3)
-
18
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
120
114
107
106
440
321
278
224
560
435
385
330
65
45
48
1
24
20
19
18
144
13
(2)
-
-
-
(3)
-
8
-
-
-
-
(3)
-
5
1
-
-
1
(2)
-
5
53
-
-
-
-
(3)
-
50
-
-
-
-
(3)
-
47
-
-
-
-
(2)
-
45
66
58
52
50
Total
662
(98)
-
-
12
(56)
(12)
508
(21)
-
-
20
(50)
-
457
36
-
-
72
(37)
(174)
354
53
-
-
-
-
(3)
-
50
-
-
-
-
(3)
-
47
-
-
-
-
(2)
-
45
715
558
504
399
Years Ended
December 31
Developed
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Undeveloped
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Total
120
114
107
106
-
-
-
-
-
-
-
-
-
-
-
-
337
235
209
101
-
-
-
-
103
86
69
123
-
-
-
-
457
349
316
207
-
-
-
-
103
86
69
123
-
-
-
-
57
45
47
1
-
-
-
-
8
-
1
-
-
-
-
-
18
16
15
16
-
-
-
-
6
4
4
2
-
-
-
-
11
8
5
2
53
50
47
45
2
-
-
3
-
-
-
-
543
418
383
226
53
50
47
45
119
90
74
128
-
-
-
-
Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2017, included:
(cid:120) Revisions: In 2017, revisions in Lower 48 were primarily due to higher prices. In 2015, revisions in Lower 48 and
Canada were primarily due to lower prices.
(cid:120) Extensions and discoveries: In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling
success in the Permian Unconventional, Eagle Ford and Bakken.
(cid:120)
Sales: In 2017, Lower 48 sales were due to the disposition of our interests in the San Juan Basin and Panhandle assets,
while Canada sales were due to the disposition of a majority of our western Canada assets.
145
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Equity affiliates
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Total company
End of 2014
End of 2015
End of 2016
End of 2017
Natural Gas
Billions of Cubic Feet
Alaska
48
Lower Total
Asia Pacific/
U.S. Canada Europe Middle East
2,719
(293)
-
-
4
(83)
-
2,347
(105)
-
-
2
(73)
(69)
2,102
287
-
-
2
(71)
-
2,320
6,945
(884)
-
-
103
(588)
(405)
5,171
(124)
-
-
162
(494)
(1)
4,714
460
-
-
582
(338)
(2,885)
2,533
9,664
(1,177)
-
-
107
(671)
(405)
7,518
(229)
-
-
164
(567)
(70)
6,816
747
-
-
584
(409)
(2,885)
4,853
1,916
(111)
1
-
44
(261)
(482)
1,107
111
-
1
43
(192)
(33)
1,037
8
-
-
3
(71)
(966)
11
1,573
(27)
-
-
-
(187)
-
1,359
56
-
-
-
(177)
-
1,238
167
-
-
-
(188)
-
1,217
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,719
2,347
2,102
2,320
6,945
5,171
4,714
2,533
9,664
7,518
6,816
4,853
1,916
1,107
1,037
11
1,573
1,359
1,238
1,217
146
1,878
110
8
-
2
(285)
-
1,713
18
1
-
124
(288)
(42)
1,526
16
-
-
23
(267)
-
1,298
5,242
(2)
-
-
268
(239)
-
5,269
(676)
-
-
125
(337)
-
4,381
111
-
-
185
(374)
-
4,303
7,120
6,982
5,907
5,601
Africa
Total
227
-
-
-
-
-
-
227
-
-
-
-
-
-
227
-
-
-
-
(3)
-
224
15,258
(1,205)
9
-
153
(1,404)
(887)
11,924
(44)
1
1
331
(1,224)
(145)
10,844
938
-
-
610
(938)
(3,851)
7,603
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,242
(2)
-
-
268
(239)
-
5,269
(676)
-
-
125
(337)
-
4,381
111
-
-
185
(374)
-
4,303
227
227
227
224
20,500
17,193
15,225
11,906
Years Ended
December 31
Developed
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Undeveloped
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Natural Gas
Billions of Cubic Feet
Alaska
48
Lower Total
Asia Pacific/
U.S. Canada Europe Middle East
2,663
2,313
2,094
2,310
5,922
4,458
4,199
1,597
8,585
6,771
6,293
3,907
1,801
1,101
1,031
11
1,182
1,088
998
997
-
-
-
-
56
34
8
10
-
-
-
-
-
-
-
-
-
-
-
-
1,023
713
515
936
1,079
747
523
946
-
-
-
-
-
-
-
-
-
-
-
-
115
6
6
-
-
-
-
-
-
-
-
-
391
271
240
220
-
-
-
-
1,553
1,421
1,188
945
3,954
4,482
4,110
4,044
325
292
338
353
1,288
787
271
259
Africa
Total
226
227
227
224
13,347
10,608
9,737
6,084
-
-
-
-
3,954
4,482
4,110
4,044
1
-
-
-
-
-
-
-
1,911
1,316
1,107
1,519
1,288
787
271
259
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, 2017, included:
(cid:120) Revisions: In 2017, revisions in Alaska, Lower 48 and Europe were primarily due to higher prices. In 2016, revisions
in our equity affiliates in Asia Pacific/Middle East were primarily due to lower prices. In 2015, revisions in Lower 48,
Alaska and Canada were primarily due to lower prices, partially offset by positive revisions in Asia Pacific/Middle East
from Indonesia.
(cid:120) Extensions and discoveries: In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling
success in the Permian Unconventional, Eagle Ford and Bakken. In 2015, for our equity affiliates in Asia
Pacific/Middle East, extensions and discoveries were due to APLNG’s ongoing development drilling onshore
Australia.
(cid:120) Sales: In 2017, Lower 48 sales were due to the disposition of our interests in the San Juan Basin and Panhandle assets,
while Canada sales were due to the disposition of a majority of our western Canada assets. In 2015, Lower 48 sales
were due to the disposition of noncore assets in South Texas, East Texas and North Louisiana and sales of assets in
British Columbia, Saskatchewan and Alberta impacted Canada.
147
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Equity affiliates
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Total company
End of 2014
End of 2015
End of 2016
End of 2017
148
Bitumen
Millions of Barrels
Canada
598
94
-
-
-
(5)
-
687
(515)
-
-
-
(13)
-
159
16
-
-
96
(21)
-
250
1,468
190
-
-
99
(51)
-
1,706
(573)
-
-
10
(54)
-
1,089
-
-
-
-
(23)
(1,066)
-
2,066
2,393
1,248
250
Years Ended
December 31
Developed
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Undeveloped
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Bitumen
Millions of Barrels
Canada
13
111
159
154
187
311
322
-
585
576
-
96
1,281
1,395
767
-
Notable changes in proved bitumen reserves in the three years ended December 31, 2017, included:
(cid:120) Revisions: In 2017, revisions were primarily due to higher prices at Surmont. In 2016, for both our
consolidated operations and equity affiliates revisions were primarily related to lower prices which
resulted in reserve reductions at Surmont, Foster Creek, Christina Lake and Narrows Lake. In 2015,
for both our consolidated operations and equity affiliates revisions were primarily related to reduced
royalties from lower prices at Surmont, Foster Creek, Christina Lake and Narrows Lake.
(cid:120) Extensions and discoveries: In 2017, extensions and discoveries were primarily due to higher prices at
Surmont, which allowed undeveloped reserves previously de-booked due to low prices to be
recognized. In 2015, for our equity affiliates extensions and discoveries were related to approval of
development at Christina Lake.
(cid:120)
Sales: In 2017, sales were due to the disposition of our 50 percent interest in the FCCL Partnership.
149
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Equity affiliates
End of 2014
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2017
Total company
End of 2014
End of 2015
End of 2016
End of 2017
Lower
48
Alaska
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Asia Pacific/
Total
Other
U.S. Canada Europe Middle East Africa Areas
Total
1,636
(165)
4
-
20
(75)
-
1,420
(77)
6
-
33
(76)
(12)
1,294
166
6
-
41
(77)
-
1,430
2,274
(301)
4
-
84
(211)
(79)
1,771
(143)
3
-
124
(185)
-
1,570
170
-
-
378
(144)
(621)
1,353
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
3,910
(466)
8
-
104
(286)
(79)
3,191
(220)
9
-
157
(261)
(12)
1,006
66
2
-
10
(62)
(92)
930
(484)
-
-
9
(55)
(7)
2,864
336
6
-
419
(221)
(621)
2,783
393
18
-
-
97
(37)
(217)
254
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,468
190
-
-
99
(51)
-
1,706
(573)
-
-
10
(54)
-
1,089
-
-
-
-
(23)
(1,066)
-
697
(26)
-
-
-
(78)
-
593
11
-
-
-
(76)
-
528
68
-
-
-
(79)
-
517
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
553
(12)
32
-
8
(84)
-
497
9
7
-
28
(87)
(10)
444
36
-
-
7
(81)
-
406
1,025
(1)
-
-
45
(48)
-
1,021
(113)
-
-
21
(64)
-
865
18
-
-
31
(69)
-
845
242
-
-
-
-
-
-
242
-
-
-
-
(1)
-
241
-
-
-
-
(8)
-
233
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6,408
(438)
42
-
122
(510)
(171)
5,453
(684)
16
-
194
(480)
(29)
4,470
458
6
-
523
(426)
(838)
4,193
5
-
-
-
-
(1)
(4)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,498
189
-
-
144
(100)
(4)
2,727
(686)
-
-
31
(118)
-
1,954
18
-
-
31
(92)
(1,066)
845
1,636
1,420
1,294
1,430
2,274
1,771
1,570
1,353
3,910
3,191
2,864
2,783
2,474
2,636
1,482
254
697
593
528
517
1,578
1,518
1,309
1,251
242
242
241
233
5
-
-
-
8,906
8,180
6,424
5,038
150
Years Ended
December 31
Developed
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Undeveloped
Consolidated operations
End of 2014
End of 2015
End of 2016
End of 2017
Equity affiliates
End of 2014
End of 2015
End of 2016
End of 2017
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Asia Pacific/
Middle East
Canada
Europe
Africa
Other
Areas
Total
Alaska
Lower
48
Total
U.S.
1,514
1,318
1,203
1,319
1,637
1,261
1,165
682
3,151
2,579
2,368
2,001
-
-
-
-
759
612
496
782
-
-
-
-
122
102
91
111
-
-
-
-
-
-
-
-
637
510
405
671
-
-
-
-
393
352
391
158
187
311
322
-
613
578
2
96
-
-
-
-
1,281
1,395
767
-
452
398
365
372
-
-
-
-
245
195
163
145
-
-
-
-
412
384
309
281
810
890
820
802
141
113
135
125
215
131
45
43
237
242
241
233
-
-
-
-
5
-
-
-
-
-
-
-
-
-
-
-
5
-
-
-
-
-
-
-
-
-
-
-
4,645
3,955
3,674
3,045
1,002
1,201
1,142
802
1,763
1,498
796
1,148
1,496
1,526
812
43
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 1,191 million BOE of proved undeveloped reserves at year-end 2017, compared with 1,608 million BOE at year-end
2016. The following table shows changes in total proved undeveloped reserves for 2017:
End of 2016
Transfers to proved developed
Revisions
Improved recovery
Purchases
Extensions and discoveries
Sales
End of 2017
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
1,608
(194)
29
6
-
527
(785)
1,191
Sales were primarily due to the disposition of our 50 percent interest in the FCCL Partnership, which were partially offset by
extensions and discoveries primarily in the Lower 48, Alaska, Canada and Asia Pacific/Middle East.
As a result, at December 31, 2017, our proved undeveloped reserves represented 24 percent of total proved reserves, compared
with 25 percent at December 31, 2016. Costs incurred for the year ended December 31, 2017, relating to the development of
151
proved undeveloped reserves were $3.5 billion. A portion of our costs incurred each year relates to development projects where
the proved undeveloped reserves will be converted to proved developed reserves in future years.
At the end of 2017, more than 90 percent of total proved undeveloped reserves are currently under development or scheduled
for development within five years of initial disclosure. The remainder are to be developed as parts of major projects ongoing in
our Europe and Asia Pacific/Middle East regions. All major development areas are currently producing and are expected to
have proved undeveloped reserves convert to proved developed over time. Approximately 74 percent of our total proved
undeveloped reserves at year-end 2017 are in North America, and all of these reserve volumes are planned for development
within five years of initial disclosure.
Results of Operations
The company’s results of operations from oil and gas activities for the years 2017, 2016 and 2015 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:
(cid:120) Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty
interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final
delivery point using transportation operations which are not consolidated.
(cid:120) Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final
delivery point using transportation operations which are consolidated.
(cid:120) Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of
hydrocarbons, and other miscellaneous income.
(cid:120) Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the
production of petroleum liquids and natural gas.
(cid:120) Taxes other than income taxes include production, property and other non-income taxes.
(cid:120) Depreciation of support equipment is reclassified as applicable.
(cid:120) Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other
miscellaneous expenses.
152
Results of Operations
Year Ended
December 31, 2017
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Alaska
Lower
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Other
Areas
Total
Millions of Dollars
$
$
$
$
3,542
4
(706)
14
2,854
985
275
83
4,557
-
-
28
4,585
1,669
318
584
8,099
4
(706)
42
7,439
2,654
593
667
705
-
-
2,158
2,863
609
33
22
730
179
2,685
3,969
(7)
62
63
52
557
(4,765)
(678) (2,424)
(2,341)
1,235
3,415
4,148
55
115
(4,208)
(3,102)
(1,106)
438
22
7
16
1,716
(651)
2,367
3,527
-
-
68
3,595
775
32
45
1,234
46
57
172
1,234
702
532
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
528
-
-
5
533
174
7
1
150
-
4
2
195
26
169
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,752
411
(80)
11
3,094
574
39
97
1,283
-
60
37
1,004
363
641
563
1,398
-
-
1,961
363
604
1,699
617
1,717
22
11
(3,072)
(998)
(2,074)
487
-
-
48
535
44
2
61
16
-
6
-
406
428
(22)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
322
322
-
-
45
-
-
-
-
277
11
266
15,570
415
(786)
2,649
17,848
4,656
699
937
6,386
4,216
185
340
429
(2,249)
2,678
-
-
-
-
-
-
-
-
1,091
1,398
-
5
2,494
537
611
1,700
-
-
19
-
(19)
13
(32)
767
1,717
45
13
(2,896)
(959)
(1,937)
153
Year Ended
December 31, 2016
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Alaska
Lower
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Other
Areas
Millions of Dollars
$
$
$
$
2,793
8
(676)
375
2,500
1,056
231
45
4,117
-
-
111
4,228
1,967
308
1,227
6,910
8
(676)
486
6,728
3,023
539
1,272
661
-
-
48
709
790
55
332
738
1
52
52
325
(29)
354
4,167
148
70
72
(3,731)
(1,349)
(2,382)
4,905
149
122
124
(3,406)
(1,378)
(2,028)
881
88
(51)
32
(1,418)
(406)
(1,012)
2,678
-
-
(34)
2,644
795
31
90
1,390
(161)
(77)
210
366
3
363
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
860
-
-
-
860
431
15
6
309
9
(7)
8
89
24
65
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,350
347
(40)
(25)
2,632
640
30
38
1,402
44
(13)
35
456
250
206
449
825
-
(2)
1,272
256
476
-
548
-
8
7
(23)
(201)
178
-
-
-
147
147
23
1
138
2
-
4
-
(21)
(72)
51
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9
9
(2)
-
41
-
-
4
-
(34)
(13)
(21)
-
-
-
-
-
-
-
-
-
-
24
-
(24)
-
(24)
Total
12,599
355
(716)
631
12,869
5,269
656
1,911
8,580
120
(11)
401
(4,057)
(1,616)
(2,441)
1,309
825
-
(2)
2,132
687
491
6
857
9
25
15
42
(177)
219
154
Year Ended
December 31, 2015
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Lower
Total
Asia Pacific/
Alaska
48 U.S. Canada
Europe Middle East Africa
Other
Areas
Millions of Dollars
$ 3,206
15
(599)
(5)
2,617
1,242
281
682
4,992
-
-
452
5,444
2,420
358
1,583
8,198
15
(599)
447
8,061
3,662
639
2,265
930
-
-
(19)
911
923
62
457
548
8
(30)
52
(166)
(89)
(77)
4,192
(2)
78
83
(3,268)
(1,193)
(2,075)
4,740
6
48
135
(3,434)
(1,282)
(2,152)
777
3
8
49
(1,368)
(244)
(1,124)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
917
-
-
34
951
474
15
12
367
-
(2)
7
78
20
58
$
$
$
3,637
-
-
(28)
3,609
1,137
35
170
1,813
724
9
240
(519)
(816)
297
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,741
629
(40)
6
3,336
815
33
268
1,321
3
(2)
34
864
430
434
536
950
-
4
1,490
248
723
190
197
1,396
(13)
10
(1,261)
(155)
(1,106)
-
-
-
13
13
42
3
990
-
-
(8)
-
(1,014)
(406)
(608)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2
2
1
1
43
-
-
5
-
(48)
(27)
(21)
50
-
-
58
108
13
13
-
5
3
23
1
50
10
40
Total
15,506
644
(639)
421
15,932
6,580
773
4,193
8,651
736
60
458
(5,519)
(2,345)
(3,174)
1,503
950
-
96
2,549
735
751
202
569
1,399
8
18
(1,133)
(125)
(1,008)
155
2017
Thousands of Barrels Daily
2016
2015
167
180
347
3
122
93
20
585
14
-
14
599
14
69
83
9
8
4
104
7
111
59
63
122
163
195
358
7
120
97
2
584
14
-
14
598
12
88
100
23
7
7
137
8
145
35
148
183
158
206
364
12
120
91
-
587
14
4
18
605
13
94
107
26
7
9
149
7
156
13
138
151
Millions of Cubic Feet Daily
7
898
905
187
476
687
8
2,263
1,007
3,270
25
1,219
1,244
524
459
730
1
2,958
899
3,857
42
1,472
1,514
715
475
717
1
3,422
638
4,060
Statistics
Net Production
Crude Oil
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Other areas
Total equity affiliates
Total company
Natural Gas Liquids
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Bitumen
Consolidated operations—Canada
Equity affiliates—Canada
Total company
Natural Gas
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
156
Average Sales Prices
Crude Oil Per Barrel
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Other areas
Total equity affiliates
Total operations
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations
Bitumen Per Barrel
Consolidated operations—Canada
Equity affiliates—Canada
2017
2016
2015
$
$
$
42.69
47.36
45.01
43.69
54.04
54.38
55.11
54.16
48.70
54.76
-
54.76
48.84
22.20
22.20
21.51
34.07
41.37
30.34
24.21
38.74
25.22
21.43
23.83
31.68
37.49
34.70
35.25
43.66
42.23
-
42.76
37.67
44.11
-
44.11
37.82
14.34
14.34
14.82
22.62
29.00
19.06
15.72
31.13
16.68
12.91
15.80
41.84
42.62
42.27
39.52
52.75
49.70
60.79
50.79
45.48
53.12
37.21
49.92
45.61
14.01
14.01
17.02
27.56
37.78
23.21
16.83
35.79
17.79
20.13
18.58
$
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
4.33
Lower 48
2.43
United States
2.47
Canada
1.91
Europe
7.14
Asia Pacific/Middle East
6.08
Africa
-
Total international
4.78
Total consolidated operations
3.77
Equity affiliates—Asia Pacific/Middle East
4.83
3.93
Total operations
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.
2.72
2.73
2.73
1.93
5.72
4.66
3.53
4.64
3.87
4.27
4.00
5.22
2.20
2.24
1.49
4.71
4.15
-
3.49
2.97
2.97
2.97
157
2017
2016
2015
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Other areas
Total equity affiliates
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada
Equity affiliates—Canada
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Other areas
Total equity affiliates
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Other areas
Total equity affiliates
*Includes bitumen.
$
$
$
$
14.83
11.46
12.52
16.36
10.16
7.42
5.74
10.08
11.34
7.57
5.26
-
5.84
14.63
18.74
4.14
2.18
2.80
0.89
0.42
0.50
0.26
0.53
1.70
0.30
8.76
-
6.64
10.99
18.44
16.10
11.76
16.18
16.58
2.09
14.96
15.55
6.52
8.94
-
8.34
16.12
11.06
12.42
14.20
10.70
7.74
31.42
10.53
11.54
7.96
4.04
-
5.85
24.59
7.96
3.53
1.73
2.21
0.99
0.42
0.36
1.37
0.55
1.44
0.28
7.52
-
4.18
11.26
23.43
20.15
15.84
18.71
16.95
2.73
17.22
18.78
5.70
8.65
-
7.29
19.12
12.17
13.88
14.88
15.05
10.20
-
13.41
13.67
9.41
5.31
8.90
7.46
61.87
9.41
4.33
1.80
2.42
1.00
0.46
0.41
-
0.62
1.61
0.30
15.48
8.90
7.62
8.43
21.07
17.96
12.52
24.00
16.53
-
17.98
17.97
7.29
4.22
3.42
5.77
158
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, 2017, 2016 and 2015. 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
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
Development
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Other areas
Total equity affiliates
*Our total proportionate interest was less than one.
Productive
2016
2017
2015
2017
2016
2015
Dry
-
47
47
16
*
1
*
-
64
19
19
18
347
365
47
10
3
-
-
425
22
166
*
188
-
3
3
-
*
1
-
1
5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1
1
2
1
1
-
-
-
4
-
-
-
-
-
2
-
-
-
-
2
-
-
-
-
-
4
4
3
*
2
*
-
9
*
-
-
-
-
-
-
*
-
-
-
-
2
-
2
-
13
13
13
*
1
-
-
27
14
14
9
161
170
13
7
8
-
-
198
19
84
-
103
2
8
10
8
*
1
1
-
20
20
20
9
119
128
47
7
6
-
-
188
48
108
-
156
159
The table below represents the status of our wells drilling at December 31, 2017, 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, 2017.
Wells at December 31, 2017
Productive*
In Progress
Gross
Net
Oil
Gross
Net
Gross
Net
Gas
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates
176
Asia Pacific/Middle East
Total equity affiliates
176
*Includes 18 gross and 6 net multiple completion wells.
1
354
355
1
22
3
-
381
1
179
180
1
3
1
-
185
47
47
1,721
9,984
11,705
182
486
370
825
13,568
-
-
769
4,781
5,550
91
86
153
135
6,015
-
-
-
5,222
5,222
42
181
55
9
5,509
3,749
3,749
-
2,364
2,364
34
68
28
2
2,496
907
907
Acreage at December 31, 2017
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
Thousands of Acres
Developed
Gross
Net
Undeveloped
Gross
Net
592
2,278
2,870
187
797
1,596
358
-
5,808
294
1,934
2,228
105
244
742
59
-
3,378
1,345
10,632
11,977
3,251
2,454
12,568
12,545
560
43,355
1,014
8,509
9,523
1,772
720
6,462
2,049
323
20,849
872
872
201
201
5,445
5,445
1,432
1,432
160
Costs Incurred
Year Ended
December 31
2017
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
2016
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
2015
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
Alaska
Lower
48
Total
U.S. Canada
Asia Pacific/
Europe Middle East * Africa
Other
Areas
Total
Millions of Dollars
$
$
$
$
$
$
$
$
$
$
$
$
18
-
18
74
736
828
267
35
302
399
1,559
2,260
285
35
320
473
2,295
3,088
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
110
720
830
127
5
132
656
782
1,570
127
5
132
766
1,502
2,400
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
76
-
76
56
102
234
-
-
-
6
150
156
59
19
78
286
209
573
-
-
-
15
367
382
-
-
-
52
784
836
-
-
-
-
-
-
-
-
-
65
62
127
-
-
-
-
-
-
-
-
-
87
1,217
1,304
168
5
173
1,369
2,875
4,417
168
5
173
1,456
4,092
5,721
52
1
53
298
827
1,178
-
-
-
107
1,742
1,849
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
17
847
864
-
-
-
-
-
-
15
-
15
139
388
542
-
-
-
38
403
441
-
-
-
52
387
439
2
-
2
19
320
341
-
-
-
118
587
705
-
-
-
60
753
813
-
-
-
61
10
71
-
-
-
-
-
-
-
-
-
215
6
221
-
-
-
-
-
-
-
-
-
394
4
398
-
-
-
-
-
-
-
-
-
42
-
42
-
-
-
-
-
-
-
-
-
67
-
67
-
-
-
-
-
-
-
-
-
47
-
47
-
-
-
-
3
3
376
35
411
823
3,579
4,813
-
-
-
44
553
597
186
24
210
1,451
2,166
3,827
2
-
2
34
687
723
220
6
226
2,420
7,252
9,898
-
-
-
77
1,603
1,680
*Certain amounts in Asia Pacific/Middle East equity affiliates have been revised in 2016 and 2015 to reflect additional abandonment obligations.
161
Capitalized Costs
At December 31
2017
Consolidated operations
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Equity affiliates
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
2016
Consolidated operations
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Equity affiliates
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Alaska
Lower Total
U.S.
48
Millions of Dollars
Other
Asia Pacific/
Canada Europe Middle East * Africa Areas
Total
$ 18,149
1,068
19,217
35,332 53,481
2,205
36,469 55,686
1,137
6,217 27,221
290
7,202 27,511
985
14,236
822
15,058
889
122
1,011
- 102,044
67
4,491
67 106,535
9,497
$ 9,720
24,211 33,708
12,258 21,978
1,582 18,068
9,443
5,620
8,916
6,142
312
699
9
58
62,595
43,940
$
$
-
-
-
-
-
$ 17,376
1,099
18,475
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,750
2,215
11,965
5,342
6,623
-
-
-
-
-
-
-
-
-
-
9,750
2,215
11,965
5,342
6,623
46,050 63,426 16,970 24,858
269
47,426 65,901 18,405 25,127
1,435
1,376
2,475
13,837
787
14,624
879
123
1,002
- 119,970
61
5,150
61 125,120
8,548
$ 9,927
26,858 35,406 10,344 15,754
9,373
20,568 30,495
8,061
7,635
6,989
297
705
1
60
69,437
55,683
$
$
-
-
-
-
-
-
-
-
-
-
9,459
-
-
891
- 10,350
-
-
1,906
8,444
-
-
-
-
-
8,839
2,756
11,595
1,369
10,226
-
-
-
-
-
-
-
-
-
-
18,298
3,647
21,945
3,275
18,670
*Certain amounts in Asia Pacific/Middle East equity affiliates have been revised in 2016 to reflect additional abandonment obligations.
162
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
2017
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
Lower
Alaska
48
Total
U.S.
Millions of Dollars
Asia Pacific/
Canada Europe Middle East Africa
Total
$ 44,969
44,556
89,525
5,479
23,137
15,207
13,181
146,529
29,524
7,255
53
8,137
2,712
5,425
$
18,947
10,881
2,375
12,353
4,358
7,995
48,471
18,136
2,428
20,490
7,070
13,420
4,417
696
-
366
78
288
8,128
8,758
3,333
2,918
289
2,629
5,398
2,511
2,459
4,839
1,032
3,807
1,401
537
10,356
887
422
465
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
23,222
12,984
1,444
2,083
6,711
2,316
4,395
-
-
-
-
-
-
-
67,815
30,638
18,576
29,500
8,891
20,609
23,222
12,984
1,444
2,083
6,711
2,316
4,395
$
5,425
7,995
13,420
288
2,629
8,202
465
25,004
163
2016
Consolidated operations
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
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
Lower
Alaska
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Total
Millions of Dollars
$ 29,697
31,963
61,660
4,739
18,533
12,770
10,715
108,417
$
$
$
$
24,965 16,936
8,932
744
5,351
976
(86) 4,375
7,961
-
(3,229)
(3,143)
5,103
1,586
-
41,901
16,893
744
2,122
(2,167) (1,297)
4,289
(1,950) 1,440
(2)
(653) 1,442
7,469
9,949
(325)
5,288
2,777
1,563
3,142
572
2,570
1,420
537
7,885
873
370
503
61,181
31,742
9,867
5,627
(2,524)
8,151
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
15,139
-
-
-
-
-
-
8,514
4,993
164
1,468
540
928
-
-
-
-
-
-
-
17,829
-
32,968
10,620
980
1,309
4,920
1,911
3,009
-
-
-
-
-
-
19,134
5,973
1,473
6,388
2,451
3,937
(86) 4,375
4,289
275
1,442
5,579
503
12,088
164
2015
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
Lower
Alaska
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Total
Millions of Dollars
$ 44,054 42,575
86,629
22,317
27,782
19,368
13,875
169,971
32,732 21,638
9,885 12,967
844
7,126
1,573
5,553
-
1,437
(502)
1,939
$
54,370
22,852
844
8,563
1,071
7,492
13,103
6,471
-
2,743
1,265
1,478
10,574
12,793
1,506
2,909
733
2,176
7,529
2,884
2,708
6,247
1,349
4,898
1,422
437
10,998
1,018
500
518
86,998
45,437
16,056
21,480
4,918
16,562
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
36,211
-
-
-
-
-
-
16,417
11,869
1,648
6,277
3,827
2,450
-
-
-
-
-
-
-
34,257
-
70,468
17,874
2,391
3,117
10,875
4,298
6,577
-
-
-
-
-
-
34,291
14,260
4,765
17,152
8,125
9,027
$
1,939
5,553
7,492
3,928
2,176
11,475
518
25,589
165
Sources of Change in Discounted Future Net Cash Flows
Consolidated Operations
2017
2016
2015
Millions of Dollars
Equity Affiliates
Total Company
2017
2016
2015
2017
2016
2015
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
Accretion of discount
Net change in income taxes
Total changes
Discounted future net cash flows
at year end
$
8,151
16,562
56,348
3,937
9,027
26,869
12,088
25,589
83,217
(9,844)
(6,313)
(8,158)
(1,341)
(956)
(966)
(11,185)
(7,269)
(9,124)
19,310
(16,476)
(82,923)
2,750
(9,317)
(27,670)
22,060
(25,793)
(110,593)
1,445
3,653
1,358
3,118
1,791
6,854
(4)
426
(77)
722
319
1,493
1,441
4,079
1,281
3,840
2,110
8,347
1,225
6,646
2,073
(64)
2,435
(227)
1,161
9,081
1,846
-
2
-
-
(855)
(123)
(424)
(786)
-
-
-
-
2
-
(38)
(1,641)
(123)
(462)
2,300
1,313
(6,089)
12,458
(3,252)
2,540
4,089
(8,411)
(1,790)
9,342
33,449
(39,786)
(648)
413
(288)
458
(436)
1,058
1,481
(5,090)
938
3,297
5,012
(17,842)
1,652
1,726
(6,377)
12,916
(3,688)
3,598
5,570
(13,501)
(852)
12,639
38,461
(57,628)
20,609
8,151
16,562
4,395
3,937
9,027
25,004
12,088
25,589
(cid:120) The net change in prices and production costs is the beginning-of-year reserve-production forecast multiplied by the net
annual change in the per-unit sales price and production cost, discounted at 10 percent.
(cid:120) Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using
production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less
future estimated costs, discounted at 10 percent.
(cid:120) Revisions of previous quantity estimates are calculated using production forecast changes for the year, including changes in
the timing of production, multiplied by the 12-month average sales prices, less future estimated costs, discounted at
10 percent.
(cid:120) The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production and
development costs.
(cid:120) The net change in income taxes is the annual change in the discounted future income tax provisions.
166
Selected Quarterly Financial Data (Unaudited)
Sales and
Other
Operating
Revenues
$
7,518
6,781
6,688
8,119
Millions of Dollars
Income (Loss)
Before
Income Taxes
(232)
(4,361)
653
1,325
Net
Income
(Loss)
599
(3,426)
436
1,598
Net Income
(Loss)
Attributable to
ConocoPhillips
Per Share of Common Stock
Net Income (Loss)
Attributable
to ConocoPhillips
Basic
Diluted
586
(3,440)
420
1,579
0.47
(2.78)
0.35
1.32
0.47
(2.78)
0.34
1.32
2017
First
Second
Third
Fourth
$
2016
First
Second
Third
Fourth
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.
(1,456)
(1,058)
(1,026)
(19)
(1,469)
(1,071)
(1,040)
(35)
(2,224)
(1,644)
(1,654)
(8)
5,121
5,348
6,415
6,809
(1.18)
(0.86)
(0.84)
(0.03)
(1.18)
(0.86)
(0.84)
(0.03)
167
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:
(cid:120) ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I (in each
case, reflecting investments in subsidiaries utilizing the equity method of accounting).
(cid:120) All other nonguarantor subsidiaries of ConocoPhillips.
(cid:120) The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
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
was reflected in the full-year 2016 condensed consolidating financial statements.
In 2017, ConocoPhillips Company received a $9.8 billion return of capital from a nonguarantor subsidiary to
settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial
statements.
In 2017, ConocoPhillips received a $5.0 billion return of capital from ConocoPhillips Company to settle
certain accumulated intercompany balances. The transaction had no impact on our consolidated financial
statements.
In 2017, ConocoPhillips received a $3.0 billion distribution from ConocoPhillips Company to settle certain
accumulated intercompany balances. This consisted of a $2.8 billion return of capital and a $0.2 billion return
of earnings. This transaction had no impact on our consolidated financial statements.
In 2017, ConocoPhillips Company received a $1.4 billion loan repayment from a nonguarantor subsidiary to
settle certain accumulated intercompany balances. This transaction had no impact on our consolidated
financial statements.
This condensed consolidating financial information should be read in conjunction with the accompanying
consolidated financial statements and notes.
168
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Gain on dispositions
Other income
Intercompany revenues
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
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Other expense
Total Costs and Expenses
Income (Loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Comprehensive Income (Loss) Attributable to ConocoPhillips
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Gain on dispositions
Other income
Intercompany revenues
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
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Loss before income taxes
Income tax benefit
Net loss
Less: net income attributable to noncontrolling interests
Net Loss Attributable to ConocoPhillips
Comprehensive Loss Attributable to ConocoPhillips
Millions of Dollars
Year Ended December 31, 2017
ConocoPhillips
ConocoPhillips
Company
ConocoPhillips
Canada Funding
Company I
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
$
$
$
-
(454)
-
2
48
(404)
-
-
9
-
-
-
-
-
420
(43)
267
653
(1,057)
(202)
(855)
-
(855)
12,433
2,047
916
35
291
15,722
11,145
832
476
544
855
1,159
140
32
664
11
35
15,893
(171)
283
(454)
-
(454)
-
-
-
-
170
170
-
-
-
-
-
-
-
-
147
156
-
303
(133)
7
(140)
-
(140)
16,673
630
1,261
492
3,405
22,461
4,580
4,358
82
394
5,990
5,442
669
330
508
(89)
-
22,264
197
(1,910)
2,107
(62)
2,045
-
(1,451)
-
-
(3,914)
(5,365)
(3,250)
(17)
(6)
-
-
-
-
-
(641)
-
-
(3,914)
(1,451)
-
(1,451)
-
(1,451)
29,106
772
2,177
529
-
32,584
12,475
5,173
561
938
6,845
6,601
809
362
1,098
35
302
35,199
(2,615)
(1,822)
(793)
(62)
(855)
(180)
221
23
2,703
(2,947)
(180)
Year Ended December 31, 2016
-
(3,351)
-
1
88
(3,262)
-
-
8
-
-
-
-
-
506
(19)
495
(3,757)
(142)
(3,615)
-
(3,615)
10,352
(1,051)
120
(11)
277
9,687
9,144
779
581
1,231
1,178
67
162
46
622
2
13,812
(4,125)
(774)
(3,351)
-
(3,351)
-
-
-
-
220
220
-
-
-
-
-
-
-
-
207
174
381
(161)
(9)
(152)
-
(152)
13,341
(91)
240
265
3,036
16,791
3,562
5,131
140
684
7,884
72
577
379
570
(176)
18,823
(2,032)
(1,046)
(986)
(56)
(1,042)
-
4,545
-
-
(3,621)
924
(2,712)
(243)
(6)
-
-
-
-
-
(660)
-
(3,621)
4,545
-
4,545
-
23,693
52
360
255
-
24,360
9,994
5,667
723
1,915
9,062
139
739
425
1,245
(19)
29,890
(5,530)
(1,971)
(3,559)
(56)
4,545
(3,615)
(3,561)
(3,297)
(27)
(952)
4,276
(3,561)
169
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Gain on dispositions
Other income
Intercompany revenues
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
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Income (loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Comprehensive Income (Loss) Attributable to ConocoPhillips
Millions of Dollars
Year Ended December 31, 2015
ConocoPhillips
ConocoPhillips
Company
ConocoPhillips
Canada Funding
Company I
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
-
(4,081)
-
-
74
(4,007)
-
-
9
-
-
-
-
-
485
114
608
(4,615)
(187)
(4,428)
-
(4,428)
11,473
(1,950)
332
12
341
10,208
9,905
1,469
744
2,093
1,201
15
173
58
423
1
16,082
(5,874)
(1,793)
(4,081)
-
(4,081)
-
-
-
-
246
246
-
-
1
-
-
-
-
-
226
(708)
(481)
727
21
706
-
706
18,091
1,364
259
113
3,365
23,192
5,838
5,585
209
2,099
7,912
2,230
728
425
447
518
25,991
(2,799)
(909)
(1,890)
(57)
(1,947)
-
5,322
-
-
(4,026)
1,296
(3,317)
(38)
(10)
-
-
-
-
-
(661)
-
(4,026)
5,322
-
5,322
-
5,322
29,564
655
591
125
-
30,935
12,426
7,016
953
4,192
9,113
2,245
901
483
920
(75)
38,174
(7,239)
(2,868)
(4,371)
(57)
(4,428)
(8,773)
(8,426)
71
(6,705)
15,060
(8,773)
170
Balance Sheet
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments, loans and long-term receivables*
Net properties, plants and equipment
Other assets
Total Assets
Liabilities and Stockholders’ Equity
Accounts payable
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits*
Total Liabilities
Retained earnings
Other common stockholders’ equity
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
Balance Sheet
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments, loans and long-term receivables*
Net properties, plants and equipment
Other assets
Total Assets
Liabilities and Stockholders’ Equity
Accounts payable
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits*
Total Liabilities
Retained earnings
Other common stockholders’ equity
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
*Includes intercompany loans.
ConocoPhillips
ConocoPhillips
Company
Millions of Dollars
At December 31, 2017
ConocoPhillips
Canada Funding
Company I
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
234
-
2,255
1,899
163
278
4,829
47,974
4,230
1,146
58,179
3,094
2,505
107
554
314
6,574
9,321
432
-
1,335
5,229
22,891
13,317
21,971
-
58,179
358
-
1,968
84
116
2,526
64,434
6,301
2,194
75,455
4,683
999
85
489
271
6,527
12,635
925
-
1,901
10,391
32,379
14,015
29,061
-
75,455
4
-
35
-
-
6
45
2,533
-
186
2,764
1
7
-
-
48
56
1,703
-
-
-
926
2,685
(681)
760
-
2,764
6,087
1,873
4,870
-
897
779
14,506
15,050
41,930
1,302
72,788
3,799
77
931
171
612
5,590
2,794
7,199
6,263
519
9,215
31,580
11,958
29,056
194
72,788
At December 31, 2016
13
-
23
-
8
44
2,296
-
220
2,560
1
6
-
-
40
47
1,710
-
-
-
748
2,505
(541)
596
-
2,560
3,239
50
6,103
934
415
10,741
31,643
52,030
1,240
95,654
3,671
94
399
200
536
4,900
2,866
7,500
10,972
651
17,832
44,721
12,883
37,798
252
95,654
-
-
(2,864)
-
-
(29)
(2,893)
(84,897)
(477)
(1,542)
(89,809)
(2,864)
(9)
-
-
(30)
(2,903)
(477)
-
(981)
-
(15,629)
(19,990)
(18,070)
(51,749)
-
(89,809)
-
-
(4,702)
-
(24)
(4,726)
(114,602)
-
(2,534)
(121,862)
(4,702)
-
-
-
(24)
(4,726)
-
-
(2,023)
-
(27,863)
(34,612)
(19,834)
(67,416)
-
(121,862)
6,325
1,873
4,320
1,899
1,060
1,035
16,512
10,060
45,683
1,107
73,362
4,030
2,575
1,038
725
1,029
9,397
17,128
7,631
5,282
1,854
1,269
42,561
29,391
1,216
194
73,362
3,610
50
3,414
1,018
517
8,609
21,672
58,331
1,160
89,772
3,653
1,089
484
689
994
6,909
26,186
8,425
8,949
2,552
1,525
54,546
31,548
3,426
252
89,772
$
$
$
$
$
$
$
$
-
-
24
-
-
1
25
29,400
-
15
29,440
-
(5)
-
-
85
80
3,787
-
-
-
1,528
5,395
22,867
1,178
-
29,440
-
-
22
-
2
24
37,901
-
40
37,965
-
(10)
-
-
171
161
8,975
-
-
-
417
9,553
25,025
3,387
-
37,965
171
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
$
Statement of Cash Flows
Year Ended December 31, 2016
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net purchases of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Provided by (Used in) Financing Activities
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net purchases of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
$
Millions of Dollars
Year Ended December 31, 2017
ConocoPhillips
ConocoPhillips
Canada Funding
ConocoPhillips
Company
Company I
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
71
1,183
(74)
8,931
(3,034)
7,077
-
-
7,765
-
-
658
1,151
-
9,574
-
(5,459)
115
(3,000)
(1,305)
4
(9,645)
-
-
-
-
(1,663)
194
11,146
-
(214)
1,527
101
(8)
11,083
20
(4,411)
-
-
(235)
(7,765)
(12,391)
1
(124)
358
234
-
-
-
-
-
-
-
-
-
65
-
-
-
-
-
65
-
(9)
13
4
(3,795)
(62)
12,796
(1,790)
(85)
2,196
(1,252)
44
8,052
214
(2,272)
-
-
(2,977)
(9,331)
(14,366)
231
2,848
3,239
6,087
867
-
(17,847)
-
299
(4,266)
-
-
(20,947)
(299)
4,266
(178)
-
3,212
16,980
23,981
-
-
-
-
(4,591)
132
13,860
(1,790)
-
115
-
36
7,762
-
(7,876)
(63)
(3,000)
(1,305)
(112)
(12,356)
232
2,715
3,610
6,325
$
(306)
(322)
(2)
5,903
(870)
4,403
(989)
(126)
266
-
(812)
391
1,433
1
164
2,994
(164)
-
-
-
(2,315)
515
(3)
354
4
358
-
-
-
-
-
1,250
-
-
1,250
-
(1,250)
-
-
-
-
(1,250)
-
(2)
15
13
(4,281)
(205)
1,114
(51)
-
272
781
(3)
(2,373)
812
(2,492)
-
-
(1,081)
184
(2,577)
(63)
890
2,349
3,239
401
-
(2,394)
-
812
(1,805)
-
-
(2,986)
(812)
1,805
(211)
-
1,081
1,993
3,856
-
-
-
-
(4,869)
(331)
1,286
(51)
-
108
-
(2)
(3,859)
4,594
(2,251)
(63)
(126)
(1,253)
(137)
764
(66)
1,242
2,368
3,610
-
-
2,300
-
-
-
(2,214)
-
86
1,600
(150)
148
(126)
(1,253)
1
220
-
-
-
-
172
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Dividends paid
Other
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
$
Millions of Dollars
Year Ended December 31, 2015
ConocoPhillips
ConocoPhillips
Canada Funding
ConocoPhillips
Company
Company I
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
(225)
245
9
7,519
24
7,572
-
-
3,500
-
-
102
-
3,602
-
-
283
(3,664)
4
(3,377)
-
-
-
-
(3,064)
(4)
826
(278)
-
46
304
(2,170)
4,743
(100)
-
-
(3,484)
1,159
-
(766)
770
4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(1)
8
7
15
(8,386)
(964)
1,225
(2,245)
205
(148)
1
(10,312)
278
(103)
(2)
(339)
1,204
1,038
(181)
(1,936)
4,285
2,349
1,400
-
(3,599)
2,523
(100)
-
1
225
(2,523)
100
(363)
339
2,198
(249)
-
-
-
-
(10,050)
(968)
1,952
-
105
-
306
(8,655)
2,498
(103)
(82)
(3,664)
(78)
(1,429)
(182)
(2,694)
5,062
2,368
173
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
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, 2017, 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, 2017.
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 76 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm
This report is included in Item 8 on page 78 and is incorporated herein by reference.
Item 9B. OTHER INFORMATION
None.
174
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on page 26.
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
2018 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2018, and
is incorporated herein by reference.*
Item 11. EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2018
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2018, and is
incorporated herein by reference.*
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2018
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2018, and is
incorporated herein by reference.*
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2018
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2018, and is
incorporated herein by reference.*
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2018
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2018, 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 2018 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.
175
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV
(a) 1. Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements,
which appears on page 75, are filed as part of this annual report.
2. Financial Statement Schedules
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.
3. Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 177 through 187, are filed as part
of this annual report.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
Millions of Dollars
Balance at Charged to
Expense
January 1
Other (a) Deductions
Balance at
December 31
80
65
-
19
5
675
2
560 (c)
Description
2017
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
2016
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
2015
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
(8)
(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)Includes an adjustment to the U.S. tax basis due to U.S. Tax Legislation.
(d)Benefit payments.
7
734
5
970
3
(31)
(2)
(21)
(1)
(12)
4
6
129
303
156
61
1
1
(3) (b)
-
(93) (d)
(4) (b)
(16)
(206) (d)
- (b)
(221)
(200) (d)
4
1,254
53
5
675
80
7
734
156
176
CONOCOPHILLIPS
INDEX TO EXHIBITS
Description
Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
Purchase and Sale Agreement, dated March 29, 2017, by and among ConocoPhillips
Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy
Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC)
Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March
31, 2017 filed by ConocoPhillips on May 4, 2017).
Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and
among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips
Canada Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada
(BRC) Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18,
2017; File No. 001-32395).
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008;
File No. 001-32395).
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips
(incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K
filed on August 30, 2002; File No. 000-49987).
Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of October 9, 2015
(incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K
filed on October 13, 2015; File No. 001-32395).
ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total
amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips
and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon
request.
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
Exhibit
Number
2.1
2.2†‡
2.3†‡
3.1
3.2
3.3
10.1
10.2
177
Exhibit
Number
Description
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10.1
10.10.2
10.10.3
10.11.1
10.11.2
10.11.3
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 001-00720).
Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated
April 19, 2012 (incorporated by reference to Exhibit 10.14 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2002; File No. 000-49987).
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference
to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Amendment and Restatement of ConocoPhillips Key Employee Supplemental Retirement Plan,
dated April 19, 2012 (incorporated by reference to Exhibit 10.13 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
First Amendment to the ConocoPhillips Key Employee Supplemental Retirement Plan, dated July
20, 2015 (incorporated by reference to Exhibit 10.10.2 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2015; File No. 001-32395).
Second Amendment to the ConocoPhillips Key Employee Supplemental Retirement Plan, dated
March 14, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-32395).
Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips—Title I,
dated April 19, 2012 (incorporated by reference to Exhibit 10.11.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips—Title II,
dated April 19, 2012 (incorporated by reference to Exhibit 10.11.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
First Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated
October 11, 2012 (incorporated by reference to Exhibit 10.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012; File No. 001-32395).
178
Exhibit
Number
10.11.4
10.12
10.13
10.14
10.15
10.16
10.17.1
10.17.2
10.17.3
10.17.4
10.17.5
10.17.6
Description
Second Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips—Title II,
dated December 17, 2015 (incorporated by reference to Exhibit 10.11.4 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Amendment and Restatement of 1998 Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2002; File No. 000-49987).
Amendment and Restatement of 1998 Key Employee Stock Performance Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2002; File No. 000-49987).
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit
10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of
the Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended
December 31, 1999; File No. 001-14521).
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998 (incorporated by
reference to Exhibit 10.17.3 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2015; File No. 001-32395).
First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated May 3, 1999 (incorporated by reference to Exhibit 10.17.4 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated January 15, 2002 (incorporated by reference to Exhibit 10.17.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated October 5, 2006 (incorporated by reference to Exhibit 10.17.6 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
179
Exhibit
Number
10.17.7
10.17.8
10.18.1
10.18.2
10.19
10.20.1
10.20.2
10.20.3
10.20.4
10.20.5
Description
Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 1, 2012 (incorporated by reference to Exhibit 10.17.7 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 20, 2015 (incorporated by reference to Exhibit 10.17.8 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
File No. 000-49987).
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarterly period ended June 30, 2008; File No. 001-32395).
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2003; File No. 000-49987).
Amendment and Restatement of Key Employee Deferred Compensation Plan of
ConocoPhillips—Title I, dated April 19, 2012 (incorporated by reference to Exhibit 10.12.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No.
001-32395).
Amendment and Restatement of Key Employee Deferred Compensation Plan of
ConocoPhillips—Title II, dated April 19, 2012 (incorporated by reference to Exhibit 10.12.2 to
the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File
No. 001-32395).
First Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title II
(incorporated by reference to Exhibit 10.20.3 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2010; File No. 001-32395).
Second Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title
II (incorporated by reference to Exhibit 10.20.4 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2010; File No. 001-32395).
Amendment and Restatement of Key Employee Deferred Compensation Plan of
ConocoPhillips—Title II, 2013 Restatement dated November 17, 2014 (Amended and Restated
effective as of January 1, 2013) (incorporated by reference to Exhibit 10.20.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2014; File No. 001-
32395).
10.21
Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance
Plan, effective January 1, 2014 (incorporated by reference to Exhibit 10.21 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2013; File No. 001-32395).
180
Exhibit
Number
10.22
10.23.1
10.23.2
10.23.3
10.24
10.25
10.26.1
10.26.2
10.26.3
10.26.4
10.26.5
Description
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No.
001-32395).
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the
2004 Annual Meeting of Shareholders; File No. 000-49987).
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2008; File No. 001-32395).
Form of Performance Share Unit Award Agreement under the Performance Share Program under
the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2008; File No. 001-32395).
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7,
2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2007; File No. 001-32395).
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the
2009 Annual Meeting of Shareholders; File No. 001-32395).
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the
2011 Annual Meeting of Shareholders; File No. 001-32395).
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
effective February 9, 2012 (incorporated by reference to Exhibit 10 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).
Form of Restricted Stock Units Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, effective April 4, 2012
(incorporated by reference to Exhibit 10.6 to the Quarterly Report of ConocoPhillips on Form 10-
Q for the quarter ended June 30, 2012; File No. 001-32395).
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, effective May 8, 2012
(incorporated by reference to Exhibit 10.7 to the Quarterly Report of ConocoPhillips on Form 10-
Q for the quarter ended June 30, 2012; File No. 001-32395).
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 18, 2012
(incorporated by reference to Exhibit 10.26.5 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2012; File No. 001-32395).
181
Exhibit
Number
10.26.6
10.26.7
10.26.8
10.26.9
10.26.10
10.26.11
10.26.12
Description
Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.6 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2012; File No. 001-32395).
Form of Performance Share Unit Agreement—Canada under the Restricted Stock Program under
the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5,
2013 (incorporated by reference to Exhibit 10.26.7 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2012; File No. 001-32395).
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.8 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2012; File No. 001-32395).
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 5, 2013 (incorporated by reference to Exhibit 10.26.9 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2012; File No. 001-32395).
Form of Make-up Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated January 1, 2012 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31,
2013; File No. 001-32395).
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 18, 2014 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.12 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.26.13 Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock
Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.2 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.14
Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.14 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
001-32395).
10.26.15 Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.3 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
182
Exhibit
Number
Description
10.26.16 Form of Performance Period IX Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.17 Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.5 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.18 Form of Performance Period X Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.6 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.19 Form of Performance Period XII Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.9 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.20 Form of Performance Period XII Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.10 to
the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File
No. 001-32395).
10.26.21
10.26.22
Form of Performance Period XIV Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
001-32395).
Form of Performance Period XIV Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.24 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File
No. 001-32395).
10.26.23 Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated March 31, 2014 (incorporated by reference to
Exhibit 10.11 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2014; File No. 001-32395).
10.26.24* Form of Performance Share Unit Award Terms and Conditions for Performance Period 18, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 13, 2018.
183
Exhibit
Number
Description
10.26.25* Form of Performance Share Unit Award Terms and Conditions for Performance Period 18 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 13, 2018.
10.27.1
10.27.2
10.27.3
10.27.4
10.27.5
10.27.6
10.27.7
10.27.8
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 14,
2014; File No. 001-32395).
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program of ConocoPhillips, granted under the 2014 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated September 15, 2014 (incorporated
by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the
quarter ended September 30, 2014; File No. 001-32395).
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 3, 2015 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2015; File No. 001-32395).
Form of Retention Award Terms and Conditions, as part of the Restricted Stock Unit Award,
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-
Q for the quarter ended March 31, 2015; File No. 001-32395).
Form of Non-Employee Director Restricted Stock Units Terms and Conditions, as part of the
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15,
2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips on
Form 10-Q for the quarter ended March 31, 2016; File No. 001-32395).
Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Canadian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No.
001-32395).
Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Norwegian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.5 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No.
001-32395).
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2017 (incorporated by reference to Exhibit 10.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No.
001-32395).
184
Exhibit
Number
10.27.9
Description
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 14, 2017 (incorporated by
reference to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter
ended March 31, 2017; File No. 001-32395).
10.27.10 Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2017 (incorporated by reference to Exhibit 10.3 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No.
001-32395).
10.27.11 Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted
Stock Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2017 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No.
001-32395).
10.27.12* Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Executive
Restricted Stock Unit Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018.
10.27.13* Form of Key Employee Award Terms and Conditions for eligible employees on the Canada
payroll, as part of the ConocoPhillips Executive Restricted Stock Unit Program granted under the
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13,
2018.
10.27.14* Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted
Stock Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 13, 2018.
10.27.15* Form of Retention Award Terms and Conditions, 2017 revision, as part of the Restricted Stock
Unit Award, granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips.
10.28
Amendment and Restatement of Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated April 19, 2012 (incorporated by reference to Exhibit 10.8 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-
32395).
10.29
Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred
Compensation Plans of ConocoPhillips, dated April 19, 2012 (incorporated by reference to
Exhibit 10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June
30, 2012; File No. 001-32395).
10.30
Amendment and Restatement of the Burlington Resources Inc. Management Supplemental
Benefits Plan, dated April 19, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-
32395).
185
Exhibit
Number
10.31
10.32
10.33
Description
Amendment and Restatement of Deferred Compensation Trust Agreement for Non-Employee
Directors of Phillips Petroleum Company, dated June 23, 1995 (incorporated by reference to
Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2016; File No. 001-32395).
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form
8-K filed on May 1, 2012; File No. 001-32395).
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips
66, dated April 26, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report of
ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).
10.34
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.3 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.35
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012
(incorporated by reference to Exhibit 10.4 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.36
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.5 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.37
ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit
10.3 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2012; File No. 001-32395).
10.38
12*
21*
Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips Company, as
guarantor, Toronto Dominion (Texas) LLC, as administrative agent and the banks party thereto,
with TD Securities (USA) LLC, as lead arranger and bookrunner, dated March 18, 2016
(incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K
filed on March 21, 2016; File No. 001-32395).
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of ConocoPhillips.
23.1*
Consent of Ernst & Young LLP.
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99* Report of DeGolyer and MacNaughton.
186
Exhibit
Number
Description
101.INS* XBRL Instance Document.
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Linkbase Document.
101.DEF* XBRL Definition Linkbase Document.
101.LAB* XBRL Labels Linkbase Document.
101.PRE* XBRL Presentation Linkbase Document.
* Filed herewith.
† The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ConocoPhillips agrees to
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
‡ ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
187
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.
SIGNATURES
February 20, 2018
CONOCOPHILLIPS
/s/ Ryan M. Lance
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 20, 2018, on behalf of the registrant by the following officers in the capacity indicated and by a
majority of directors.
Signature
Title
/s/ Ryan M. Lance
Ryan M. Lance
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Chairman of the Board of Directors
and Chief Executive Officer
(Principal executive officer)
Executive Vice President, Finance,
Commercial and Chief Financial Officer
(Principal financial officer)
/s/ Glenda M. Schwarz
Glenda M. Schwarz
Vice President and Controller
(Principal accounting officer)
188
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
/s/ Richard L. Armitage
Richard L. Armitage
/s/ Richard H. Auchinleck
Richard H. Auchinleck
/s/ Charles E. Bunch
Charles E. Bunch
/s/ Caroline M. Devine
Caroline M. Devine
/s/ Gay Huey Evans
Gay Huey Evans
/s/ John V. Faraci
John V. Faraci
/s/ Jody Freeman
Jody Freeman
/s/ Sharmila Mulligan
Sharmila Mulligan
/s/ Arjun N. Murti
Arjun N. Murti
/s/ Robert A. Niblock
Robert A. Niblock
/s/ Harald J. Norvik
Harald J. Norvik
189
Board of Directors
(As of Feb. 20, 2018)
Richard L. Armitage
President, Armitage International LLC,
Former U.S. Deputy Secretary of State
Gay Huey Evans, OBE
Deputy Chairman,
Financial Reporting Council
Richard H. Auchinleck
Former President and Chief Executive
Officer, Gulf Canada Resources
Limited
Charles E. Bunch
Former Chairman and Chief Executive
Officer, PPG Industries, Inc.
Caroline Maury Devine
Former President and Managing
Director of a Norwegian affiliate
of ExxonMobil
John V. Faraci
Former Chairman and Chief Executive
Officer, International Paper Company
Jody Freeman
Archibald Cox Professor of Law,
Harvard Law School
Executive Leadership Team
(As of Feb. 20, 2018)
Ryan M. Lance
Chairman and Chief Executive Officer
Matt J. Fox
Executive Vice President, Strategy,
Exploration and Technology
Ryan M. Lance
Chairman and Chief Executive Officer,
ConocoPhillips
Sharmila Mulligan
Founder and Chief Executive Officer,
ClearStory Data Inc.
Arjun N. Murti
Senior Advisor, Warburg Pincus
Robert A. Niblock
Chairman, President and
Chief Executive Officer, Lowe’s
Companies, Inc.
Harald J. Norvik
Former Chairman, President and
Chief Executive Officer, Statoil
Janet Langford Carrig
Senior Vice President, Legal, General
Counsel and Corporate Secretary
Andrew D. Lundquist
Senior Vice President, Government Affairs
Al J. Hirshberg
Executive Vice President, Production,
Drilling and Projects
Ellen R. DeSanctis
Vice President, Investor Relations and
Communications
Don E. Wallette, Jr.
Executive Vice President, Finance,
Commercial and Chief Financial Officer
James D. McMorran
Vice President, Human Resources and
Real Estate and Facilities Services
Explore
ConocoPhillips
Fact Sheets
The ConocoPhillips fact
sheets provide detailed
operational updates for
each of the company’s six
segments. The fact sheets
are updated annually
and are available at
www.conocophillips.com/
factsheets.
Sustainability Report
The Conoco Phillips
Sustainability Report
provides an overview of
the company’s sustainable
development programs
and metrics. The 2017
Sustainability Report will
be available in June at
www.conocophillips.com/
sustainability.
Certain disclosures in this annual report may be considered “forward-looking” statements. These are made pursuant to “safe harbor” provisions of the Private Securities
Litigation Reform Act of 1995. The “Cautionary Statement” in the Management’s Discussion and Analysis in ConocoPhillips’ 2017 Form 10-K should be read in conjunction
with such statements.
“ConocoPhillips,” “the company,” “we,” “us” and “our” are used interchangeably in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries.
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