|
Notes to Consolidated Financial Statements
|
ConocoPhillips
|
Note 1—Basis of Presentation
The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2018 Annual Report on Form 10-K.
Note 2—Changes in Accounting Principles
We adopted the provisions of FASB ASU No. 2016-02, “Leases,” and its amendments set forth by the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU No. 2018-10, “Codification Improvements to Topic 842, Leases,” ASU No. 2018-11, “Targeted Improvements,” ASU No. 2018-20, “Narrow-Scope Improvements for Lessors,” and ASU No. 2019-01, “Codification Improvements,” collectively FASB ASC Topic 842, “Leases” (ASC Topic 842), beginning January 1, 2019.
ASC Topic 842 establishes comprehensive accounting and financial reporting requirements for leasing arrangements, supersedes the existing requirements in FASB ASC Topic 840, “Leases” (ASC Topic 840), and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASC Topic 842 also modify the definition of a lease and outline requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors.
We adopted ASC Topic 842 using the modified retrospective approach and elected to utilize the Optional Transition Method, which permits us to apply the provisions of ASC Topic 842 to leasing arrangements existing at or entered into after January 1, 2019, and present in our financial statements comparative periods prior to January 1, 2019 under the historical requirements of ASC Topic 840. In addition, we elected to adopt the package of optional transition-related practical expedients, which among other things, allows us to carry forward certain historical conclusions reached under ASC Topic 840 regarding lease identification, classification, and the accounting treatment of initial direct costs. Furthermore, we elected not to record assets and liabilities on our consolidated balance sheet for new or existing lease arrangements with terms of 12 months or less.
The primary impact of applying ASC Topic 842 is the initial recognition of $
998
million of lease liabilities and corresponding right-of-use assets on our consolidated balance sheet as of January 1, 2019, for leases classified as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing arrangements. Our accounting treatment for finance leases remains unchanged. In addition, there is no cumulative effect to retained earnings or other components of equity recognized as of January 1, 2019, and the adoption of ASC Topic 842 did not impact the presentation of our consolidated income statement or statement of cash flows. See Note 15—Non-Mineral Leases for additional information related to the adoption of ASC Topic 842.
We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” beginning January 1, 2019. The ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act, eliminating the stranded tax effects.
The cumulative effect to our consolidated balance sheet at January 1, 2019 for the adoption of ASU No. 2018-02 was as follows:
|
|
Millions of Dollars
|
|
|
|
December 31
|
|
ASU No. 2018-02
|
|
January 1
|
|
|
|
2018
|
|
Adjustments
|
|
2019
|
|
Equity
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
|
$
|
(
6,063)
|
|
(
40)
|
|
(
6,103)
|
|
Retained earnings
|
|
34,010
|
|
40
|
|
34,050
|
|
For additional information regarding the impact of the adoption of ASU No. 2018-02, see Note 16—Accumulated Other Comprehensive Loss.
|
Note 3—Variable Interest Entities
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 CBM, 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 June 30, 2019, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, for additional information.
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. 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.
Based on inputs related to the fair value of MWCC observed in the second quarter of 2019, we reduced the carrying value of our equity method investment in MWCC to $
30 million and recorded a before-tax impairment of $
95 million which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. For additional information see Note 14—Fair Value Measurement.
At June 30, 2019, the carrying value of our equity method investment in MWCC was $
29 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.
|
Note 4—Inventories
|
|
|
|
|
|
|
|
|
|
|
|
Inventories consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
June 30
|
|
December 31
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
Crude oil and natural gas
|
$
|
481
|
|
432
|
|
Materials and supplies
|
|
608
|
|
575
|
|
|
$
|
1,089
|
|
1,007
|
Inventories valued on the LIFO basis totaled $
255 million and $
292 million at June 30, 2019 and December 31, 2018, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was $
156 million and $
75 million at June 30, 2019 and December 31, 2018, respectively.
Note 5—Assets Held for Sale and Dispositions
Assets Held for Sale
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $
2.675 billion plus interest and customary adjustments. Together the subsidiaries indirectly hold the company’s exploration and production assets in the U.K. As of June 30, 2019, the net carrying value was approximately $
0.8 billion and the assets were considered held for sale resulting in the reclassification of $
1.6 billion of PP&E and $
0.2 billion of “Other assets”, primarily right-of-use assets, to “Prepaid expenses and other current assets”, and $
1.9 billion of noncurrent liabilities, primarily asset retirement obligations, to “Other accruals” on our consolidated balance sheet. As a result of entering into the transaction agreement, we recognized a U.S. tax benefit of $
234 million in the second quarter of 2019, primarily related to the recognition of U.S. tax basis in our U.K. subsidiaries to be sold. Depending on the timing of regulatory approval and satisfaction of conditions precedent, we anticipate recognizing an additional gain of approximately $
2
billion before- and after-tax on completion of the sale in the second half of 2019, subject to customary adjustments and foreign exchange impacts. The before tax earnings associated with the subsidiaries being sold were $
293 million and $
432 million for the six-month periods ended June 30, 2019 and June 30, 2018, respectively. Results of operations for the U.K. are reported within our Europe and North Africa segment.
Asset Dispositions
In the second quarter of 2019, we recognized an after-tax gain of $
52 million upon the closing of the sale of our
30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $
350 million, before customary adjustments. The Greater Sunrise Fields were included in our Asia Pacific and Middle East segment.
In January 2019, we entered into agreements to sell our
12.4 percent ownership interests in the Golden Pass LNG Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual obligations for retaining use of the facilities. As a result of entering into these agreements, we recorded a before-tax impairment of $
60 million in the first quarter of 2019 which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019. Results of operations for these assets are reported in our Lower 48 segment. See Note 14—Fair Value Measurement for additional information.
In the second quarter of 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 included a five-year uncapped contingent payment. The contingent payment, calculated on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52 CAD per barrel. Contingent payments received during the five-year period are recorded as “Gain on dispositions” on our consolidated income statement and reflected in our Canada segment. We recorded gains on dispositions for these contingent payments of $
19 million and $
56 million in the first and second quarters of 2019, respectively, and $
50 million in the second quarter of 2018.
Note 6—Investments, Loans and Long-Term Receivables
APLNG
APLNG executed project financing agreements for an $
8.5 billion project finance facility in 2012. The $8.5 billion project finance facility was initially 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. All amounts have been drawn from the facility. APLNG made its first principal and interest repayment in
March 2017
and is scheduled to make
bi-annual payments until
March 2029
.
APLNG made a voluntary repayment of $
1.4 billion to the Export-Import Bank of China in September 2018. At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $
1.4 billion. APLNG made its first interest payment related to this facility in
March 2019
, and principal payments are scheduled to commence in
September 2023
, with
bi-annual payments due on the facility until
September 2030
.
During the first quarter of 2019, APLNG refinanced $
3.2 billion of existing project finance debt through two transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $
2.6 billion. Interest and principal payments are scheduled to commence in
September 2019
, with bi-annual payments due on the facility until
March 2028
. Through the second transaction, APLNG obtained a USPP bond facility of $
0.6 billion. Interest payments are scheduled to commence in Se
ptember 2019
, and principal payments are scheduled to commence in
September 2023
, with
bi-annual payments due on the facility until
September 2030
.
In conjunction with the $3.2 billion debt obtained during the first quarter of 2019 to refinance existing project finance debt, APLNG made voluntary repayments of $
2.2 billion and $
1.0 billion to a syndicate of Australian and international commercial banks and the Export-Import Bank of China, respectively.
At June 30, 2019, a balance of $
6.9 billion was outstanding on the facilities. See Note 11—Guarantees, for additional information.
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 3—Variable Interest Entities, for additional information.
At June 30, 2019, the carrying value of our equity method investment in APLNG was $
7,357 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.
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 made to certain affiliated and non-affiliated companies. At June 30, 2019, significant loans to affiliated companies included $
399 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).
On our consolidated balance sheet, the long-term portion of these loans is included in the “Loans and advances—related parties” line, while the short-term portion is in the “Accounts and notes receivable—related parties” line.
Note 7—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, at closing, approximated
16.9 percent of issued and outstanding Cenovus common stock. 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 on the closing date.
Our investment on our consolidated balance sheet as of June 30, 2019, is carried at fair value of $
1.84 billion, reflecting the closing price of Cenovus Energy shares on the New York Stock Exchange of $
8.82 per share on the last trading day of the quarter, an increase of $
30 million from $
1.81 billion at the end of the first quarter of 2019 and an increase of $
373 million from $
1.46 billion at year-end 2018. The increase in fair value represents the net unrealized gain recorded within the “Other income” line of our consolidated income statement in the first six months of 2019 relating to the shares held at the reporting date. See Note 14—Fair Value Measurement, for additional information.
Subject to market conditions, we intend to decrease our investment over time through market transactions, private agreements or otherwise.
Note 8—Suspended Wells
The capitalized cost of suspended wells at June 30, 2019, was $
1,001 million, an increase of $
145 million from $
856 million at year-end 2018.
No
suspended wells were charged to dry hole expense during the first six months of 2019 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2018.
Note 9—Debt
Our revolving credit facility provides a total commitment of $
6.0 billion and expires in
May 2023
. 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 program. Our commercial paper program consists of the ConocoPhillips Company $
6.0 billion program, primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to
90 days.
We had no commercial paper outstanding at June 30, 2019 or December 31, 2018. We had no direct outstanding borrowings or letters of credit under the revolving credit facility at June 30, 2019 or December 31, 2018. Since we had
no
commercial paper outstanding and had issued
no
letters of credit, we had access to $
6.0 billion in borrowing capacity under our revolving credit facility at June 30, 2019.
At June 30, 2019, 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. If they are ever redeemed, we intend to refinance on a long-term basis, therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.
|
Note 10—Changes in Equity
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Attributable to ConocoPhillips
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
Par Value
|
|
Capital in Excess of Par
|
|
Treasury Stock
|
Accum. Other Comprehensive Income (Loss)
|
|
Retained Earnings
|
|
Non-Controlling Interests
|
|
Total
|
|
For the three months ended June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at March 31, 2019
|
$
|
18
|
|
46,877
|
|
(
43,656)
|
|
(
5,914)
|
|
35,534
|
|
122
|
|
32,981
|
|
Net income
|
|
|
|
|
|
|
|
|
|
1,580
|
|
17
|
|
1,597
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
87
|
|
|
|
|
|
87
|
|
Dividends paid ($
0.31 ) per common share
|
|
|
|
|
|
|
|
|
|
(
346)
|
|
|
|
(
346)
|
|
Repurchase of company common stock
|
|
|
|
|
|
(
1,250)
|
|
|
|
|
|
|
|
(
1,250)
|
|
Distributions to noncontrolling interests and other
|
|
|
|
|
|
|
|
|
|
|
|
(
43)
|
|
(
43)
|
|
Distributed under benefit plans
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
45
|
|
Other
|
|
|
|
|
|
|
|
|
|
1
|
|
2
|
|
3
|
|
Balances at June 30, 2019
|
$
|
18
|
|
46,922
|
|
(
44,906)
|
|
(
5,827)
|
|
36,769
|
|
98
|
|
33,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the six months ended June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2018
|
$
|
18
|
|
46,879
|
|
(
42,905)
|
|
(
6,063)
|
|
34,010
|
|
125
|
|
32,064
|
|
Net income
|
|
|
|
|
|
|
|
|
|
3,413
|
|
30
|
|
3,443
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
276
|
|
|
|
|
|
276
|
|
Dividends paid ($
0.61 ) per common share
|
|
|
|
|
|
|
|
|
|
(
696)
|
|
|
|
(
696)
|
|
Repurchase of company common stock
|
|
|
|
|
|
(
2,002)
|
|
|
|
|
|
|
|
(
2,002)
|
|
Distributions to noncontrolling interests and other
|
|
|
|
|
|
|
|
|
|
|
|
(
60)
|
|
(
60)
|
|
Distributed under benefit plans
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
43
|
|
Changes in Accounting Principles*
|
|
|
|
|
|
|
|
(
40)
|
|
40
|
|
|
|
-
|
|
Other
|
|
|
|
|
|
1
|
|
|
|
2
|
|
3
|
|
6
|
|
Balances at June 30, 2019
|
$
|
18
|
|
46,922
|
|
(
44,906)
|
|
(
5,827)
|
|
36,769
|
|
98
|
|
33,074
|
|
*See Note 2
—
Changes in Accounting Principles for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Attributable to ConocoPhillips
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
Par Value
|
|
Capital in
Excess of Par
|
|
Treasury Stock
|
|
Accum. Other Comprehensive Income (Loss)
|
|
Retained Earnings
|
|
Non-Controlling Interests
|
|
Total
|
|
For the three months ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at March 31, 2018
|
$
|
18
|
|
46,642
|
|
(
40,406)
|
|
(
5,371)
|
|
29,663
|
|
172
|
|
30,718
|
|
Net income
|
|
|
|
|
|
|
|
|
|
1,640
|
|
14
|
|
1,654
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
(
266)
|
|
|
|
|
|
(
266)
|
|
Dividends paid ($
0.29 ) per common share
|
|
|
|
|
|
|
|
|
|
(
337)
|
|
|
|
(
337)
|
|
Repurchase of company common stock
|
|
|
|
|
|
(
646)
|
|
|
|
|
|
|
|
(
646)
|
|
Distributions to noncontrolling interests and other
|
|
|
|
|
|
|
|
|
|
|
|
(
8)
|
|
(
8)
|
|
Distributed under benefit plans
|
|
|
|
104
|
|
|
|
|
|
|
|
|
|
104
|
|
Other
|
|
|
|
|
|
|
|
|
|
1
|
|
2
|
|
3
|
|
Balances at June 30, 2018
|
$
|
18
|
|
46,746
|
|
(
41,052)
|
|
(
5,637)
|
|
30,967
|
|
180
|
|
31,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the six months ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2017
|
$
|
18
|
|
46,622
|
|
(
39,906)
|
|
(
5,518)
|
|
29,391
|
|
194
|
|
30,801
|
|
Net income
|
|
|
|
|
|
|
|
|
|
2,528
|
|
26
|
|
2,554
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
(
177)
|
|
|
|
|
|
(
177)
|
|
Dividends paid ($
0.57 ) per common share
|
|
|
|
|
|
|
|
|
|
(
675)
|
|
|
|
(
675)
|
|
Repurchase of company common stock
|
|
|
|
|
|
(
1,146)
|
|
|
|
|
|
|
|
(
1,146)
|
|
Distributions to noncontrolling interests and other
|
|
|
|
|
|
|
|
|
|
|
|
(
42)
|
|
(
42)
|
|
Distributed under benefit plans
|
|
|
|
124
|
|
|
|
|
|
|
|
|
|
124
|
|
Changes in Accounting Principles*
|
|
|
|
|
|
|
|
58
|
|
(
278)
|
|
|
|
(
220)
|
|
Other
|
|
|
|
|
|
|
|
|
|
1
|
|
2
|
|
3
|
|
Balances at June 30, 2018
|
$
|
18
|
|
46,746
|
|
(
41,052)
|
|
(
5,637)
|
|
30,967
|
|
180
|
|
31,222
|
|
*Cumulative effect of the adoption of ASC Topic 606, “Revenue from Contracts with Customers,” and ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Liabilities,” at January 1, 2018.
|
|
|
Note 11—Guarantees
At June 30, 2019, 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 June 30, 2019, 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 June 2019 exchange rates:
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 $
170 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At June 30, 2019, the carrying value of this guarantee was approximately $
14 million. For additional information, see Note 6—Investments, Loans and Long-Term Receivables.
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 23 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $
760 million ($
1.4 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.
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 26 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $
130 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 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 four 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 June 30, 2019, was approximately $
80 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 June 30, 2019, were approximately $
30 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.
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.
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. EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries.
At June 30, 2019, our consolidated balance sheet included a total environmental accrual of $
175 million, compared with $
178 million at December 31, 2018, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next
30 years. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.
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 June 30, 2019, we had performance obligations secured by letters of credit of $
223 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, ConocoPhillips was unable to reach agreement with respect to the 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, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. 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. In March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips $
8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has filed a request for recognition of the Award in several jurisdictions. An Application for Rectification of the Award requesting correction of certain calculations was filed on behalf of the government of Venezuela, which the ICSID Tribunal is now reviewing. Once resolved, the government of Venezuela may then seek annulment of the Award.
In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $
2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into
a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $
500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years.
To date, ConocoPhillips has received initial payments as well as quarterly installment payments for the first and second quarters of 2019 for a total of approximately $
665 million. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips has ensured that the settlement meets all appropriate U.S. regulatory requirements, including any applicable sanctions imposed by the U.S. against Venezuela.
In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro project. This ICC arbitration is currently in progress.
In February 2017, the ICSID Tribunal unanimously awarded Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, $
380 million for Ecuador’s unlawful expropriation of Burlington’s investment in Blocks 7 and 21, in 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 counterclaims. In December 2017, Burlington and Ecuador entered into a settlement agreement by which Ecuador paid Burlington $
337 million in
two installments. The first installment of $
75 million was paid in December 2017, and the second installment of $
262 million was paid in April 2018. The settlement included an offset for the counterclaims decision, of which Burlington is entitled to a $
24 million contribution from Perenco Ecuador Limited, its co-venturer and consortium operator, pursuant to a joint and several liability provision in the JOA. Ecuador’s environmental and infrastructure counterclaims against Perenco remain pending in a separate ICSID arbitration between Perenco and Ecuador, and Burlington may owe Perenco a contribution under the JOA for damages found by this tribunal.
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V., now Woodside Senegal B.V., in connection with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. This arbitration is ongoing.
In late 2017, ConocoPhillips (U.K.) Limited (CPUKL) initiated United Nations Commission on International Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral Investment Treaty relating to a tax dispute arising from the 2012 sale of ConocoPhillips (U.K.) Cuu Long Limited and ConocoPhillips (U.K.) Gama Limited. The tribunal was constituted in February 2018. The arbitration is ongoing.
In 2017 and 2018, cities, counties, and a state government in California, New York, Washington, Rhode Island and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits. The lawsuits brought by the Cities of San Francisco, Oakland and New York have been dismissed by the district courts and appeals are pending. Lawsuits filed by other cities and counties in California and Maryland are currently stayed pending appeals to the U.S. Court of Appeals for the Ninth Circuit and Fourth Circuit on the issue of whether they will proceed in federal or state court.
Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations in Louisiana. All parish lawsuits are stayed pending an appeal to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or state court. ConocoPhillips will vigorously defend against these lawsuits.
Note 13—Derivative and Financial Instruments
Derivative 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 NGLs.
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 NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.
|
The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
June 30
|
|
December 31
|
|
|
2019
|
|
2018
|
|
Assets
|
|
|
|
|
|
Prepaid expenses and other current assets
|
$
|
339
|
|
410
|
|
Other assets
|
|
38
|
|
40
|
|
Liabilities
|
|
|
|
|
|
Other accruals
|
|
330
|
|
370
|
|
Other liabilities and deferred credits
|
|
28
|
|
30
|
|
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
$
|
45
|
|
(
20)
|
|
64
|
|
23
|
|
Other income
|
|
|
2
|
|
5
|
|
1
|
|
9
|
|
Purchased commodities
|
|
|
(
31)
|
|
24
|
|
(
51)
|
|
(
3)
|
|
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:
|
|
|
|
|
|
|
|
|
Open Position
|
|
Long/(Short)
|
|
|
June 30
|
|
December 31
|
|
|
2019
|
|
2018
|
|
Commodity
|
|
|
|
|
|
Natural gas and power (billions of cubic feet equivalent)
|
|
|
|
|
|
Fixed price
|
|
(19)
|
|
(17)
|
|
Basis
|
|
(12)
|
|
(1)
|
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 equity securities. We do not elect hedge accounting on our foreign currency exchange derivatives.
|
The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
June 30
|
|
December 31
|
|
|
2019
|
|
2018
|
|
Assets
|
|
|
|
|
|
Prepaid expenses and other current assets
|
$
|
-
|
|
7
|
|
Liabilities
|
|
|
|
|
|
Other accruals
|
|
9
|
|
6
|
|
Other liabilities and deferred credits
|
|
15
|
|
-
|
|
The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our consolidated income statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency transaction (gains) losses
|
|
$
|
23
|
|
2
|
|
21
|
|
(
3)
|
|
We had the following net notional position of outstanding foreign currency exchange derivatives:
|
|
|
|
|
|
|
|
|
In Millions
|
|
Notional Currency
|
|
|
|
June 30
|
|
December 31
|
|
|
2019
|
|
2018
|
|
Foreign Currency Exchange Derivatives
|
|
|
|
|
|
Sell U.S. dollar, buy British pound
|
USD
|
-
|
|
805
|
|
Sell British pound, buy other currencies*
|
GBP
|
-
|
|
21
|
|
Buy British pound, sell Euro
|
GBP
|
15
|
|
-
|
|
Sell Canadian dollar, buy U.S. dollar
|
CAD
|
1,350
|
|
1,242
|
|
*Primarily euro and Norwegian krone.
|
|
|
|
|
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 collar expired during the second quarter of 2019 and we entered into new foreign currency exchange forward contracts to sell $1.35 billion CAD at $0.748 CAD against the U.S. dollar.
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 in which we currently invest include:
Time deposits: Interest bearing deposits placed with approved financial institutions.
Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.
Government or government agency obligations: Short-term securities issued by the U.S. government or U.S. government agencies.
These financial instruments appear in the “Cash and cash equivalents” line on 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.
|
|
Millions of Dollars
|
|
|
Carrying Amount
|
|
|
Cash and Cash Equivalents
|
|
Short-Term Investments
|
|
|
June 30
|
|
December 31
|
|
June 30
|
|
December 31
|
|
|
2019
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
$
|
764
|
|
876
|
|
|
|
|
|
Time deposits
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days
|
|
4,520
|
|
3,509
|
|
42
|
|
-
|
|
Commercial paper
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days
|
|
247
|
|
229
|
|
690
|
|
248
|
|
Government obligations
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days
|
|
410
|
|
1,301
|
|
-
|
|
-
|
|
|
$
|
5,941
|
|
5,915
|
|
732
|
|
248
|
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, 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 June 30, 2019 and December 31, 2018, was $
73 million and $
62 million, respectively. For these instruments,
no
collateral was posted as of June 30, 2019 or December 31, 2018. If our credit rating had been downgraded below investment grade on June 30, 2019, we would be required to post $
71 million of additional collateral, either with cash or letters of credit.
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:
Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
Level 2: Inputs other than quoted prices that are directly or indirectly observable.
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. There were no material transfers between levels during 2019 or 2018.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in Cenovus Energy shares and commodity derivatives. Level 1 derivative assets and liabilities primarily
represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 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):
|
|
|
Millions of Dollars
|
|
|
|
June 30, 2019
|
|
December 31, 2018
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Cenovus Energy
|
$
|
1,835
|
|
-
|
|
-
|
|
1,835
|
|
1,462
|
|
-
|
|
-
|
|
1,462
|
|
Commodity derivatives
|
|
230
|
|
106
|
|
41
|
|
377
|
|
236
|
|
181
|
|
33
|
|
450
|
|
Total assets
|
$
|
2,065
|
|
106
|
|
41
|
|
2,212
|
|
1,698
|
|
181
|
|
33
|
|
1,912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
237
|
|
111
|
|
10
|
|
358
|
|
225
|
|
145
|
|
30
|
|
400
|
|
Total liabilities
|
$
|
237
|
|
111
|
|
10
|
|
358
|
|
225
|
|
145
|
|
30
|
|
400
|
|
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 setoff exists.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
Amounts Subject to Right of Setoff
|
|
|
Gross
|
|
Amounts Not
|
|
|
|
Gross
|
|
Net
|
|
|
|
|
|
|
Amounts
|
|
Subject to
|
|
Gross
|
Amounts
|
|
Amounts
|
|
Cash
|
|
Net
|
|
|
Recognized
|
|
Right of Setoff
|
|
Amounts
|
Offset
|
|
Presented
|
|
Collateral
|
|
Amounts
|
|
June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
$
|
377
|
|
10
|
|
367
|
|
267
|
|
100
|
|
-
|
|
100
|
|
Liabilities
|
|
358
|
|
5
|
|
353
|
|
267
|
|
86
|
|
7
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
$
|
450
|
|
9
|
|
441
|
|
280
|
|
161
|
|
-
|
|
161
|
|
Liabilities
|
|
400
|
|
4
|
|
396
|
|
280
|
|
116
|
|
10
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2019 and December 31, 2018, 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 2 Inputs
|
|
Before-Tax Loss
|
|
Equity method investments
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
171
|
|
171
|
|
-
|
|
60
|
|
May 31, 2019
|
$
|
30
|
|
-
|
|
30
|
|
95
|
During the first quarter of 2019, the carrying values of our equity method investments in the Golden Pass LNG Terminal and Golden Pass Pipeline were written down to fair value. The fair values were determined by negotiated selling prices. For additional information, see
Note 5—Assets Held for Sale and Dispositions.
During the second quarter of 2019, our equity method investment in MWCC was determined to have a fair value below its carrying value, and the impairment was considered to be other than temporary. For additional information, see Note 3—Variable Interest Entities.
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
Cash and cash equivalents and short-term investments: The carrying amount reported on our consolidated balance sheet approximates fair value.
Accounts and notes receivable (including long-term and related parties): The carrying amount reported on our consolidated 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 7—Investment in Cenovus Energy, for a discussion of the carrying value and fair value of our investment in Cenovus Energy shares.
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 6—Investments, Loans and Long-Term Receivables, for additional information.
Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on our consolidated balance sheet approximates fair value.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Carrying Amount
|
|
Fair Value
|
|
|
June 30
|
|
December 31
|
|
June 30
|
|
December 31
|
|
2019
|
2018
|
2019
|
|
2018
|
|
Financial assets
|
|
|
|
|
|
|
|
|
|
Investment in Cenovus Energy
|
$
|
1,835
|
|
1,462
|
|
1,835
|
|
1,462
|
|
Commodity derivatives
|
|
110
|
|
170
|
|
110
|
|
170
|
|
Total loans and advances—related parties
|
|
405
|
|
468
|
|
405
|
|
468
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
Total debt, excluding finance (capital) leases
|
|
14,183
|
|
14,191
|
|
17,770
|
|
16,147
|
|
Commodity derivatives
|
|
84
|
|
110
|
|
84
|
|
110
|
Note 15—Non-Mineral Leases
The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels, tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices and other leases include payment provisions that vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For additional information about guarantees, see Note 11—Guarantees. There are no significant restrictions imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.
Certain arrangements may contain both lease and non-lease components and we determine if an arrangement is or contains a lease at contract inception. Only the lease components of these contractual arrangements are subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting guidance; however,
we have elected to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. This policy election has been adopted for each of the company’s leased asset classes existing as of the effective date and subject to the transition provisions of ASC Topic 842 and will be applied to all new or modified leases executed on or after January 1, 2019. For contractual arrangements executed in subsequent periods involving a new leased asset class, the company will determine at contract inception whether it will apply the optional practical expedient to the new leased asset class.
Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. Future lease payments include variable lease payments that depend upon an index or rate using the index or rate at the commencement date and probable amounts owed under residual value guarantees. The amount of future lease payments may be increased to include additional payments related to lease extension, termination, and/or purchase options when the company has determined, at or subsequent to lease commencement, generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent to the commencement date based on future usage levels, the nature of leased asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with terms of 12 months or less.
We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related joint venture.
The company has historically recorded certain finance leases executed by investee companies accounted for under the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional basis consistent with its ownership interest in the investee company. In addition, the company has historically recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis pursuant to accounting guidance applicable prior to January 1, 2019. As of December 31, 2018, $
420 million of finance lease assets (net of accumulated DD&A) and $
688 million of finance lease liabilities were recorded on our consolidated balance sheet associated with these leases. In accordance with the transition provisions of ASC Topic 842, and since
we have elected to adopt the package of optional transition-related practical expedients, the historical accounting treatment for these leases has been carried forward and is subject to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term expiration.
In connection with our adoption of ASC Topic 842, we have recorded on our consolidated balance sheet $
57 million of operating leases executed by investee companies accounted for under the proportionate consolidation method of accounting on a proportional basis consistent with our ownership interest in the investee company.
The following tables summarize the finance leases amounts that were reflected on our consolidated balance sheet as of December 31, 2018, the operating leases impact of adopting ASC Topic 842, and the right-of-use asset and lease liability balances reflected for both operating and finance leases on our consolidated balance sheet as of June 30, 2019:
|
|
|
Millions of Dollars
|
|
|
|
Carrying Amount
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
Amounts recognized in line items in our Consolidated
|
|
|
|
|
|
Balance Sheet upon adoption of ASC Topic 842
|
|
|
|
|
|
|
|
|
|
|
|
Right-of-Use Assets
|
|
|
|
|
|
Properties, plants and equipment
|
|
|
|
|
|
Gross
|
|
|
$
|
1,044
|
|
Accumulated depreciation, depletion and amortization
|
|
|
|
(
550)
|
|
Net properties, plants and equipment as of December 31, 2018
|
|
|
$
|
494
|
|
|
|
|
|
|
|
Adoption of ASC Topic 842 as of January 1, 2019
|
$
|
998
|
|
|
|
|
|
|
|
|
|
Lease Liabilities
|
|
|
|
|
|
Short-term debt
|
|
|
$
|
79
|
|
Long-term debt
|
|
|
|
698
|
|
Total finance leases debt as of December 31, 2018
|
|
|
$
|
777
|
|
|
|
|
|
|
|
Adoption of ASC Topic 842 as of January 1, 2019
|
$
|
998
|
|
|
|
|
|
|
|
|
|
Amounts recognized in line items in our Consolidated
|
|
|
|
|
|
Balance Sheet at June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
Right-of-Use Assets
|
|
|
|
|
|
Properties, plants and equipment
|
|
|
|
|
|
Gross
|
|
|
$
|
1,044
|
|
Accumulated depreciation, depletion and amortization
|
|
|
|
(
608)
|
|
Net properties, plants and equipment
*
|
|
|
$
|
436
|
|
Other assets
|
$
|
1,047
|
|
|
*Includes proportionately consolidated finance lease assets (net of accumulated depreciation, depletion and amortization) of $
376 million.
|
|
|
Millions of Dollars
|
|
|
|
Carrying Amount
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
Lease Liabilities
|
|
|
|
|
|
Short-term debt
*
|
|
|
$
|
80
|
|
Other accruals
|
$
|
351
|
|
|
|
Long-term debt
*
|
|
|
|
661
|
|
Other liabilities and deferred credits
|
|
693
|
|
|
|
Total lease liabilities
|
$
|
1,044
|
|
741
|
*
Short-term debt and long-term debt include proportionately consolidated finance lease liabilities of $
55
million and $
609
million, respectively.
|
The following table summarizes our lease costs:
|
|
|
Millions of Dollars
|
|
|
Three Months Ended
|
Six Months Ended
|
|
|
June 30, 2019
|
June 30, 2019
|
|
Lease Cost
*
|
|
|
|
|
|
Operating lease cost
|
$
|
91
|
|
166
|
|
Finance lease cost
|
|
|
|
|
|
Amortization of right-of-use assets
|
|
29
|
|
58
|
|
Interest on lease liabilities
|
|
9
|
|
19
|
|
Short-term lease cost
**
|
|
16
|
|
30
|
|
Total lease cost
***
|
$
|
145
|
|
273
|
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
**Short-term leases are not recorded on our consolidated balance sheet. Our future short-term lease commitments amount to $
77 million, of
which $
65 million is related to leases whose terms have not yet commenced as of June 30, 2019.
***Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above.
|
The following table summarizes the lease term and discount rate at June 30, 2019:
|
|
|
|
|
June 30, 2019
|
|
Lease Term and Discount Rate
|
|
|
|
|
Weighted-average term (years)
|
|
|
|
|
Operating leases
|
|
|
5.56
|
|
Finance leases
|
|
|
9.21
|
|
|
|
|
|
|
Weighted-average discount rate (percent)
|
|
|
|
|
Operating leases
|
|
|
3.38
|
|
Finance leases
|
|
|
5.77
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes other lease information for the six-month period ended June 30, 2019:
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
Six Months Ended
|
|
Other Information
*
|
|
|
June 30, 2019
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
|
Operating cash flows from operating leases
|
|
$
|
101
|
|
Operating cash flows from finance leases
|
|
|
20
|
|
Financing cash flows from finance leases
|
|
|
37
|
|
|
|
|
|
|
Right-of-use assets obtained in exchange for operating lease liabilities
|
|
$
|
228
|
|
Right-of-use assets obtained in exchange for finance lease liabilities
|
|
|
-
|
|
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
|
|
|
|
|
|
|
|
The following table summarizes future lease payments for operating and finance leases at June 30, 2019:
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Operating Leases
|
|
Finance
Leases
|
|
Maturity of Lease Liabilities
|
|
|
|
|
|
2019
|
$
|
206
|
|
58
|
|
2020
|
|
327
|
|
115
|
|
2021
|
|
207
|
|
100
|
|
2022
|
|
121
|
|
98
|
|
2023
|
|
67
|
|
84
|
|
Remaining years
|
|
221
|
|
461
|
|
Total
*
|
|
1,149
|
|
916
|
|
Less: portion representing imputed interest
|
|
(
105)
|
|
(
175)
|
|
Total lease liabilities
|
$
|
1,044
|
|
741
|
|
*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee company or oil and gas venture.
|
|
|
|
|
|
|
|
At December 31, 2018, future undiscounted minimum rental payments due under noncancelable operating
|
|
leases pursuant to ASC Topic 840 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions
of Dollars
|
|
|
|
|
|
|
|
2019
|
|
|
$
|
248
|
|
2020
|
|
|
|
425
|
|
2021
|
|
|
|
136
|
|
2022
|
|
|
|
319
|
|
2023
|
|
|
|
54
|
|
Remaining years
|
|
|
|
212
|
|
Total
|
|
|
|
1,394
|
|
Less: income from subleases
|
|
|
|
(
7)
|
|
Net minimum operating lease payments
|
|
|
$
|
1,387
|
|
At December 31, 2018, future minimum payments due under finance (capital) leases pursuant to
|
|
ASC Topic 840 were:
|
|
|
|
|
|
|
|
|
|
|
|
Millions
of Dollars
|
|
|
|
|
|
|
|
2019
|
|
|
$
|
118
|
|
2020
|
|
|
|
116
|
|
2021
|
|
|
|
100
|
|
2022
|
|
|
|
98
|
|
2023
|
|
|
|
87
|
|
Remaining years
|
|
|
|
453
|
|
Total
|
|
|
|
972
|
|
Less: portion representing imputed interest
|
|
|
|
(
195)
|
|
Capital lease obligations
|
|
|
$
|
777
|
|
Note 16—Accumulated Other Comprehensive Loss
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss in the equity section of our consolidated balance sheet included:
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Defined Benefit Plans
|
|
Foreign Currency Translation
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
$
|
(
361)
|
|
(
5,702)
|
|
(
6,063)
|
|
Cumulative effect of adopting ASU No. 2018-02*
|
|
(
40)
|
|
-
|
|
(
40)
|
|
Other comprehensive income
|
|
30
|
|
246
|
|
276
|
|
June 30, 2019
|
$
|
(
371)
|
|
(
5,456)
|
|
(
5,827)
|
|
*See Note 2—Changes in Accounting Principles for additional information.
|
There were no items within accumulated other comprehensive loss related to noncontrolling interests.
|
The following table summarizes reclassifications out of accumulated other comprehensive loss and into comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30
|
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined benefit plans
|
$
|
17
|
|
127
|
|
30
|
|
138
|
The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $
5 million and $
34 million for the three months ended June 30, 2019 and June 30, 2018, respectively, and $
10 million and $
37 million for the six-month periods ended June 30, 2019 and June 30, 2018, respectively. See Note 18—Employee Benefit Plans, for additional information.
|
Note 17—Cash Flow Information
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Six Months Ended
|
|
|
|
June 30
|
|
|
|
|
2019
|
|
2018
|
|
Cash Payments
|
|
|
|
|
|
Interest
|
$
|
414
|
|
405
|
|
Income taxes
|
|
1,572
|
|
1,307
|
|
|
|
|
|
|
|
|
Net Sales (Purchases) of Short-Term Investments
|
|
|
|
|
|
Short-term investments purchased
|
$
|
(
982)
|
|
(
831)
|
|
Short-term investments sold
|
|
497
|
|
2,088
|
|
|
$
|
(
485)
|
|
1,257
|
|
Note 18—Employee Benefit Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Postretirement Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Pension Benefits
|
|
Other Benefits
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
U.S.
|
|
Int'l.
|
|
U.S.
|
|
Int'l.
|
|
|
|
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
19
|
|
18
|
|
22
|
|
22
|
|
-
|
|
1
|
|
Interest cost
|
|
21
|
|
26
|
|
27
|
|
27
|
|
3
|
|
2
|
|
Expected return on plan assets
|
|
(
18)
|
|
(
35)
|
|
(
35)
|
|
(
40)
|
|
-
|
|
-
|
|
Amortization of prior service cost (credit)
|
|
-
|
|
(
1)
|
|
-
|
|
(
2)
|
|
(
9)
|
|
(
8)
|
|
Recognized net actuarial loss (gain)
|
|
13
|
|
8
|
|
16
|
|
9
|
|
-
|
|
(
1)
|
|
Settlements
|
|
11
|
|
-
|
|
147
|
|
-
|
|
-
|
|
-
|
|
Net periodic benefit cost
|
$
|
46
|
|
16
|
|
177
|
|
16
|
|
(
6)
|
|
(
6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
39
|
|
37
|
|
43
|
|
43
|
|
-
|
|
1
|
|
Interest cost
|
|
42
|
|
52
|
|
54
|
|
54
|
|
5
|
|
4
|
|
Expected return on plan assets
|
|
(
36)
|
|
(
70)
|
|
(
69)
|
|
(
80)
|
|
-
|
|
-
|
|
Amortization of prior service cost (credit)
|
|
-
|
|
(
1)
|
|
-
|
|
(
3)
|
|
(
17)
|
|
(
17)
|
|
Recognized net actuarial loss (gain)
|
|
26
|
|
16
|
|
31
|
|
18
|
|
(
1)
|
|
(
1)
|
|
Settlements
|
|
17
|
|
-
|
|
147
|
|
-
|
|
-
|
|
-
|
|
Net periodic benefit cost
|
$
|
88
|
|
34
|
|
206
|
|
32
|
|
(
13)
|
|
(
13)
|
The components of net periodic benefit cost, other than the service cost component, are included in the “Other expenses” line item on our consolidated income statement.
During the first six months of 2019, we contributed $
108 million to our domestic benefit plans and $
77 million to our international benefit plans. In 2019, we expect to contribute approximately $
205 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $
185 million to our international qualified and nonqualified pension and postretirement benefit plans. In the event we complete our transaction to sell two ConocoPhillips subsidiaries in the U.K., we expect to make an additional contribution to an international qualified pension plan of approximately $
285 million. For additional information, see Note 5—Assets Held for Sale and Dispositions.
Severance Accrual
The following table summarizes our severance accrual activity for the six-month period ended June 30, 2019:
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
Balance at December 31, 2018
|
$
|
48
|
|
Accruals
|
|
2
|
|
Benefit payments
|
|
(
18)
|
|
Foreign currency translation adjustments
|
|
1
|
|
Balance at June 30, 2019
|
$
|
33
|
Of the remaining balance at June 30, 2019, $
14 million is classified as short term.
|
Note 19—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
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues and other income
|
$
|
26
|
|
24
|
|
47
|
|
47
|
|
Purchases
|
|
17
|
|
25
|
|
38
|
|
49
|
|
Operating expenses and selling, general and administrative
|
|
|
|
|
|
|
|
|
|
|
expenses
|
|
14
|
|
16
|
|
28
|
|
31
|
|
Net interest (income) expense*
|
|
(
3)
|
|
(
4)
|
|
(
7)
|
|
(
7)
|
|
*We paid interest to, or received interest from, various affiliates. See Note 6—Investments, Loans and Long-Term Receivables, for additional
|
|
information on loans to affiliated companies.
|
Note 20—Sales and Other Operating Revenues
Revenue from Contracts with Customers
The following table provides further disaggregation of our consolidated sales and other operating revenues:
|
|
Millions of Dollars
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from contracts with customers
|
$
|
6,633
|
|
6,743
|
|
13,692
|
|
13,288
|
|
Revenue from contracts outside the scope of ASC Topic 606
|
|
|
|
|
|
|
|
|
|
Physical contracts meeting the definition of a derivative
|
|
1,371
|
|
1,719
|
|
3,452
|
|
3,980
|
|
Financial derivative contracts
|
|
(
51)
|
|
42
|
|
(
41)
|
|
34
|
|
Consolidated sales and other operating revenues
|
$
|
7,953
|
|
8,504
|
|
17,103
|
|
17,302
|
Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 21—Segment Disclosures and Related Information:
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Revenue from Outside the Scope of ASC Topic 606
|
|
|
|
|
|
|
|
|
|
|
by Segment
|
|
|
|
|
|
|
|
|
|
Lower 48
|
$
|
1,111
|
|
1,300
|
|
2,724
|
|
3,013
|
|
Canada
|
|
100
|
|
96
|
|
341
|
|
287
|
|
Europe and North Africa
|
|
160
|
|
323
|
|
387
|
|
680
|
|
Physical contracts meeting the definition of a derivative
|
$
|
1,371
|
|
1,719
|
|
3,452
|
|
3,980
|
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Revenue from Outside the Scope of ASC Topic 606
|
|
|
|
|
|
|
|
|
|
|
by Product
|
|
|
|
|
|
|
|
|
|
Crude oil
|
$
|
165
|
|
290
|
|
353
|
|
576
|
|
Natural gas
|
|
1,095
|
|
1,363
|
|
2,863
|
|
3,253
|
|
Other
|
|
111
|
|
66
|
|
236
|
|
151
|
|
Physical contracts meeting the definition of a derivative
|
$
|
1,371
|
|
1,719
|
|
3,452
|
|
3,980
|
Practical Expedients
Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific cases may extend longer, which may be out to the end of field life.
We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly,
we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the reporting period.
Receivables and Contract Liabilities
Receivables from Contracts with Customers
At June 30, 2019, the “Accounts and notes receivable” line on our consolidated balance sheet, includes trade receivables of $
2,470 million compared with $
2,889 million at December 31, 2018, and includes both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606.
We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with gas sold under contracts for which NPNS has not been elected compared to trade receivables where NPNS has been elected.
Contract Liabilities from Contracts with Customers
We have entered into contractual arrangements where we license proprietary technology to customers related to the optimization process for operating LNG plants.
The agreements typically provide for negotiated payments to be made at stated milestones. The payments are not directly related to our performance under the contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and benefit from their right to use the license. Payments are received in installments over the construction period.
|
|
Millions of Dollars
|
|
Contract Liabilities
|
|
|
|
At December 31, 2018
|
$
|
206
|
|
Contractual payments received
|
|
57
|
|
Revenue recognized
|
|
(
133)
|
|
At June 30, 2019
|
$
|
130
|
|
|
|
|
|
Amounts Recognized in the Consolidated Balance Sheet at June, 30 2019
|
|
|
|
Current liabilities
|
$
|
60
|
|
Noncurrent liabilities
|
|
70
|
|
|
$
|
130
|
We expect to recognize the contract liabilities as of June 30, 2019, as revenue between the remainder of 2019 and 2023.
Note 21—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs 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 income and costs not directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.
|
Analysis of Results by Operating Segment
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Sales and Other Operating Revenues
|
|
|
|
|
|
|
|
|
|
Alaska
|
$
|
1,426
|
|
1,403
|
|
2,833
|
|
2,788
|
|
Lower 48
|
|
3,809
|
|
3,852
|
|
7,962
|
|
7,804
|
|
Intersegment eliminations
|
|
(
11)
|
|
(
1)
|
|
(
23)
|
|
(
4)
|
|
Lower 48
|
|
3,798
|
|
3,851
|
|
7,939
|
|
7,800
|
|
Canada
|
|
717
|
|
810
|
|
1,540
|
|
1,701
|
|
Intersegment eliminations
|
|
(
335)
|
|
(
290)
|
|
(
585)
|
|
(
545)
|
|
Canada
|
|
382
|
|
520
|
|
955
|
|
1,156
|
|
Europe and North Africa
|
|
1,313
|
|
1,644
|
|
2,859
|
|
3,252
|
|
Asia Pacific and Middle East
|
|
1,030
|
|
1,006
|
|
2,373
|
|
2,222
|
|
Corporate and Other
|
|
4
|
|
80
|
|
144
|
|
84
|
|
Consolidated sales and other operating revenues
|
$
|
7,953
|
|
8,504
|
|
17,103
|
|
17,302
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues by Geographic Location
|
|
United States
|
$
|
5,225
|
|
5,256
|
|
10,911
|
|
10,592
|
|
Australia
|
|
311
|
|
303
|
|
870
|
|
743
|
|
Canada
|
|
382
|
|
520
|
|
955
|
|
1,156
|
|
China
|
|
159
|
|
136
|
|
402
|
|
354
|
|
Indonesia
|
|
226
|
|
213
|
|
431
|
|
428
|
|
Libya
|
|
267
|
|
262
|
|
521
|
|
538
|
|
Malaysia
|
|
334
|
|
356
|
|
670
|
|
700
|
|
Norway
|
|
561
|
|
715
|
|
1,149
|
|
1,378
|
|
United Kingdom
|
|
485
|
|
668
|
|
1,189
|
|
1,337
|
|
Other foreign countries
|
|
3
|
|
75
|
|
5
|
|
76
|
|
Worldwide consolidated
|
$
|
7,953
|
|
8,504
|
|
17,103
|
|
17,302
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues by Product
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
$
|
4,813
|
|
4,776
|
|
9,394
|
|
9,226
|
|
Natural gas
|
|
1,915
|
|
2,294
|
|
4,918
|
|
5,090
|
|
Natural gas liquids
|
|
213
|
|
265
|
|
451
|
|
496
|
|
Other*
|
|
1,012
|
|
1,169
|
|
2,340
|
|
2,490
|
|
Consolidated sales and other operating revenues by product
|
$
|
7,953
|
|
8,504
|
|
17,103
|
|
17,302
|
|
*Includes LNG and bitumen.
|
|
|
Millions of Dollars
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30
|
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Net Income Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
Alaska
|
$
|
462
|
|
418
|
|
846
|
|
942
|
|
Lower 48
|
|
206
|
|
410
|
|
399
|
|
718
|
|
Canada
|
|
100
|
|
33
|
|
222
|
|
(
32)
|
|
Europe and North Africa
|
|
407
|
|
290
|
|
614
|
|
535
|
|
Asia Pacific and Middle East
|
|
517
|
|
466
|
|
1,042
|
|
927
|
|
Other International
|
|
81
|
|
(
5)
|
|
212
|
|
(
49)
|
|
Corporate and Other
|
|
(
193)
|
|
28
|
|
78
|
|
(
513)
|
|
Consolidated net income attributable to ConocoPhillips
|
$
|
1,580
|
|
1,640
|
|
3,413
|
|
2,528
|
|
|
Millions of Dollars
|
|
|
June 30
|
|
December 31
|
|
2019
|
2018
|
|
Total Assets
|
|
|
|
|
|
Alaska
|
$
|
15,392
|
|
14,648
|
|
Lower 48
|
|
14,792
|
|
14,888
|
|
Canada
|
|
6,291
|
|
5,748
|
|
Europe and North Africa
|
|
9,950
|
|
9,883
|
|
Asia Pacific and Middle East
|
|
15,230
|
|
16,151
|
|
Other International
|
|
88
|
|
89
|
|
Corporate and Other
|
|
9,518
|
|
8,573
|
|
Consolidated total assets
|
$
|
71,261
|
|
69,980
|
Note 22—Income Taxes
Our effective tax rates for the three- and six-month periods ended June 30, 2019, were
22 percent and
27 percent, respectively, compared with
37 percent and
42 percent for the same periods of 2018. T
he effective tax rate for the three- and six
-month periods ended June 30, 2019 is lower than the effective tax rate for the same periods of 2018 primarily due to the recognition of U.S. tax basis in our U.K. subsidiaries to be sold, a reduction in our valuation allowance for 2019, and higher before-tax income in lower tax jurisdictions for 2019. See discussion of these items in the paragraphs below.
During the second quarter of 2019, we recognized a U.S. tax benefit of $
234 million primarily related to the recognition of U.S. tax basis in our U.K. subsidiaries classified as held for sale.
During the three- and six-month periods ended June 30, 2019, our valuation allowance decreased by $
85 million and $
191 million, respectively, compared to a decrease of $
12 million and an increase of $
45 million for the same periods of 2018. The change to our valuation allowance between periods relates primarily to the decrease in the deferred tax asset related to the increase in the fair value measurement of our Cenovus Energy common shares as well as recognition of
deferred tax assets due to the disposition of the Greater
Sunrise Fields
.
For additional information on asset dispositions, see
Note 5—Assets Held for Sale and Dispositions.
In July 2019, all partners in the Malaysia Block G PSC approved claiming certain deepwater incentive tax credits. As a result, we expect to recognize an income tax benefit in the third quarter of 2019 of approximately $
165 million. The Malaysia assets are included in our Asia Pacific and Middle East segment.
Note 23—New Accounting Standards
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. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. The impact of the adoption of this ASU to our financial statements is expected to be immaterial.
Supplementary Inform
ation—Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is
100 percent owned by ConocoPhillips. Burlington Resources LLC is an indirect,
100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC, with respect to its 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:
ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
All other nonguarantor subsidiaries of ConocoPhillips.
The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
In December 2018, ConocoPhillips Canada Funding Company I’s guaranteed, publicly held debt securities were assumed by Burlington Resources LLC. The assumption did not significantly change the nature of the outstanding debt or the terms of the parental guarantees, which remain full and unconditional, as well as joint and several. The assumption did not impact our consolidated financial position, results of operations or cash flows. Financial information for ConocoPhillips Canada Funding Company I is presented in the “All Other Subsidiaries” column of our condensed consolidating financial information. The prior year comparative periods have been restated to reflect the current period condensed consolidating financial information presentation.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
In April 2019, ConocoPhillips received a $
1.7 billion return of earnings from ConocoPhillips Company to settle certain accumulated intercompany balances. This transaction had no impact on our consolidated financial statements.
In April 2019, ConocoPhillips Company received a $
3.3 billion return of earnings from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.
|
|
|
|
Millions of Dollars
|
|
|
|
|
Three Months Ended June 30, 2019
|
|
Income Statement
|
|
ConocoPhillips
|
|
ConocoPhillips Company
|
|
Burlington Resources LLC
|
|
All Other Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
$
|
-
|
|
3,487
|
|
-
|
|
4,466
|
|
-
|
|
7,953
|
|
Equity in earnings of affiliates
|
|
1,637
|
|
2,088
|
|
533
|
|
173
|
|
(
4,258)
|
|
173
|
|
Gain on dispositions
|
|
-
|
|
10
|
|
-
|
|
72
|
|
-
|
|
82
|
|
Other income
|
|
-
|
|
44
|
|
1
|
|
127
|
|
-
|
|
172
|
|
Intercompany revenues
|
|
-
|
|
23
|
|
10
|
|
1,782
|
|
(
1,815)
|
|
-
|
|
Total Revenues and Other Income
|
|
1,637
|
|
5,652
|
|
544
|
|
6,620
|
|
(
6,073)
|
|
8,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
-
|
|
3,124
|
|
-
|
|
946
|
|
(
1,396)
|
|
2,674
|
|
Production and operating expenses
|
|
1
|
|
657
|
|
-
|
|
1,113
|
|
(
353)
|
|
1,418
|
|
Selling, general and administrative expenses
|
|
2
|
|
83
|
|
-
|
|
44
|
|
-
|
|
129
|
|
Exploration expenses
|
|
-
|
|
47
|
|
-
|
|
75
|
|
-
|
|
122
|
|
Depreciation, depletion and amortization
|
|
-
|
|
148
|
|
-
|
|
1,342
|
|
-
|
|
1,490
|
|
Impairments
|
|
-
|
|
-
|
|
-
|
|
1
|
|
-
|
|
1
|
|
Taxes other than income taxes
|
|
-
|
|
33
|
|
-
|
|
161
|
|
-
|
|
194
|
|
Accretion on discounted liabilities
|
|
-
|
|
4
|
|
-
|
|
83
|
|
-
|
|
87
|
|
Interest and debt expense
|
|
70
|
|
143
|
|
33
|
|
(
15)
|
|
(
66)
|
|
165
|
|
Foreign currency transaction losses
|
|
-
|
|
23
|
|
-
|
|
5
|
|
-
|
|
28
|
|
Other expenses
|
|
-
|
|
13
|
|
-
|
|
1
|
|
-
|
|
14
|
|
Total Costs and Expenses
|
|
73
|
|
4,275
|
|
33
|
|
3,756
|
|
(
1,815)
|
|
6,322
|
|
Income before income taxes
|
|
1,564
|
|
1,377
|
|
511
|
|
2,864
|
|
(
4,258)
|
|
2,058
|
|
Income tax provision (benefit)
|
|
(
16)
|
|
(
260)
|
|
(
4)
|
|
741
|
|
-
|
|
461
|
|
Net income
|
|
1,580
|
|
1,637
|
|
515
|
|
2,123
|
|
(
4,258)
|
|
1,597
|
|
Less: net income attributable to noncontrolling interests
|
|
-
|
|
-
|
|
-
|
|
(
17)
|
|
-
|
|
(
17)
|
|
Net Income Attributable to ConocoPhillips
|
$
|
1,580
|
|
1,637
|
|
515
|
|
2,106
|
|
(
4,258)
|
|
1,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income Attributable to ConocoPhillips
|
$
|
1,667
|
|
1,724
|
|
623
|
|
2,182
|
|
(
4,529)
|
|
1,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement
|
|
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
$
|
-
|
|
3,680
|
|
-
|
|
4,824
|
|
-
|
|
8,504
|
|
Equity in earnings of affiliates
|
|
1,705
|
|
1,733
|
|
545
|
|
264
|
|
(
3,982)
|
|
265
|
|
Gain on dispositions
|
|
-
|
|
-
|
|
-
|
|
55
|
|
-
|
|
55
|
|
Other income
|
|
-
|
|
394
|
|
-
|
|
22
|
|
-
|
|
416
|
|
Intercompany revenues
|
|
10
|
|
34
|
|
11
|
|
1,392
|
|
(
1,447)
|
|
-
|
|
Total Revenues and Other Income
|
|
1,715
|
|
5,841
|
|
556
|
|
6,557
|
|
(
5,429)
|
|
9,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
-
|
|
3,281
|
|
-
|
|
1,128
|
|
(
1,345)
|
|
3,064
|
|
Production and operating expenses
|
|
-
|
|
253
|
|
-
|
|
1,065
|
|
(
5)
|
|
1,313
|
|
Selling, general and administrative expenses
|
|
1
|
|
81
|
|
-
|
|
36
|
|
-
|
|
118
|
|
Exploration expenses
|
|
-
|
|
38
|
|
-
|
|
31
|
|
-
|
|
69
|
|
Depreciation, depletion and amortization
|
|
-
|
|
143
|
|
-
|
|
1,295
|
|
-
|
|
1,438
|
|
Impairments
|
|
-
|
|
(
1)
|
|
-
|
|
(
34)
|
|
-
|
|
(
35)
|
|
Taxes other than income taxes
|
|
-
|
|
28
|
|
-
|
|
245
|
|
-
|
|
273
|
|
Accretion on discounted liabilities
|
|
-
|
|
5
|
|
-
|
|
84
|
|
-
|
|
89
|
|
Interest and debt expense
|
|
76
|
|
141
|
|
14
|
|
43
|
|
(
97)
|
|
177
|
|
Foreign currency transaction (gains) losses
|
|
16
|
|
-
|
|
58
|
|
(
102)
|
|
-
|
|
(
28)
|
|
Other expenses
|
|
-
|
|
148
|
|
-
|
|
(
5)
|
|
-
|
|
143
|
|
Total Costs and Expenses
|
|
93
|
|
4,117
|
|
72
|
|
3,786
|
|
(
1,447)
|
|
6,621
|
|
Income before income taxes
|
|
1,622
|
|
1,724
|
|
484
|
|
2,771
|
|
(
3,982)
|
|
2,619
|
|
Income tax provision (benefit)
|
|
(
18)
|
|
19
|
|
(
9)
|
|
973
|
|
-
|
|
965
|
|
Net income
|
|
1,640
|
|
1,705
|
|
493
|
|
1,798
|
|
(
3,982)
|
|
1,654
|
|
Less: net income attributable to noncontrolling interests
|
|
-
|
|
-
|
|
-
|
|
(
14)
|
|
-
|
|
(
14)
|
|
Net Income Attributable to ConocoPhillips
|
$
|
1,640
|
|
1,705
|
|
493
|
|
1,784
|
|
(
3,982)
|
|
1,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income Attributable to ConocoPhillips
|
$
|
1,374
|
|
1,439
|
|
302
|
|
1,429
|
|
(
3,170)
|
|
1,374
|
|
See Notes to Consolidated Financial Statements.
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
Six Months Ended June 30, 2019
|
|
Income Statement
|
|
|
ConocoPhillips
|
|
ConocoPhillips Company
|
|
Burlington Resources LLC
|
|
All Other Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
|
$
|
-
|
|
7,468
|
|
-
|
|
9,635
|
|
-
|
|
17,103
|
|
Equity in earnings of affiliates
|
|
|
|
3,527
|
|
3,710
|
|
1,006
|
|
359
|
|
(
8,241)
|
|
361
|
|
Gain (loss) on dispositions
|
|
|
|
-
|
|
5
|
|
-
|
|
94
|
|
-
|
|
99
|
|
Other income
|
|
|
|
1
|
|
552
|
|
1
|
|
320
|
|
-
|
|
874
|
|
Intercompany revenues
|
|
|
|
-
|
|
49
|
|
23
|
|
2,943
|
|
(
3,015)
|
|
-
|
|
Total Revenues and Other Income
|
|
|
|
3,528
|
|
11,784
|
|
1,030
|
|
13,351
|
|
(
11,256)
|
|
18,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
|
|
-
|
|
6,621
|
|
-
|
|
2,250
|
|
(
2,522)
|
|
6,349
|
|
Production and operating expenses
|
|
|
|
1
|
|
837
|
|
1
|
|
2,204
|
|
(
354)
|
|
2,689
|
|
Selling, general and administrative expenses
|
|
|
|
6
|
|
212
|
|
-
|
|
69
|
|
(
5)
|
|
282
|
|
Exploration expenses
|
|
|
|
-
|
|
94
|
|
-
|
|
138
|
|
-
|
|
232
|
|
Depreciation, depletion and amortization
|
|
|
|
-
|
|
284
|
|
-
|
|
2,752
|
|
-
|
|
3,036
|
|
Impairments
|
|
|
|
-
|
|
-
|
|
-
|
|
2
|
|
-
|
|
2
|
|
Taxes other than income taxes
|
|
|
|
-
|
|
79
|
|
-
|
|
390
|
|
-
|
|
469
|
|
Accretion on discounted liabilities
|
|
|
|
-
|
|
8
|
|
-
|
|
165
|
|
-
|
|
173
|
|
Interest and debt expense
|
|
|
|
139
|
|
292
|
|
66
|
|
35
|
|
(
134)
|
|
398
|
|
Foreign currency transaction (gains) losses
|
|
|
|
-
|
|
29
|
|
-
|
|
11
|
|
-
|
|
40
|
|
Other expenses
|
|
|
|
-
|
|
25
|
|
-
|
|
(
3)
|
|
-
|
|
22
|
|
Total Costs and Expenses
|
|
|
|
146
|
|
8,481
|
|
67
|
|
8,013
|
|
(
3,015)
|
|
13,692
|
|
Income (Loss) before income taxes
|
|
|
|
3,382
|
|
3,303
|
|
963
|
|
5,338
|
|
(
8,241)
|
|
4,745
|
|
Income tax provision (benefit)
|
|
|
|
(
31)
|
|
(
224)
|
|
(
9)
|
|
1,566
|
|
-
|
|
1,302
|
|
Net income (loss)
|
|
|
|
3,413
|
|
3,527
|
|
972
|
|
3,772
|
|
(
8,241)
|
|
3,443
|
|
Less: net income attributable to noncontrolling interests
|
|
|
|
-
|
|
-
|
|
-
|
|
(
30)
|
|
-
|
|
(
30)
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
$
|
3,413
|
|
3,527
|
|
972
|
|
3,742
|
|
(
8,241)
|
|
3,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss) Attributable to ConocoPhillips
|
|
|
$
|
3,689
|
|
3,803
|
|
1,204
|
|
3,998
|
|
(
9,005)
|
|
3,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement
|
|
|
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
|
$
|
-
|
|
7,444
|
|
-
|
|
9,858
|
|
-
|
|
17,302
|
|
Equity in earnings of affiliates
|
|
|
|
2,659
|
|
3,232
|
|
879
|
|
472
|
|
(
6,769)
|
|
473
|
|
Gain on dispositions
|
|
|
|
-
|
|
3
|
|
-
|
|
59
|
|
-
|
|
62
|
|
Other income
|
|
|
|
-
|
|
291
|
|
-
|
|
73
|
|
-
|
|
364
|
|
Intercompany revenues
|
|
|
|
19
|
|
90
|
|
13
|
|
2,591
|
|
(
2,713)
|
|
-
|
|
Total Revenues and Other Income
|
|
|
|
2,678
|
|
11,060
|
|
892
|
|
13,053
|
|
(
9,482)
|
|
18,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
|
|
-
|
|
6,691
|
|
-
|
|
2,561
|
|
(
2,474)
|
|
6,778
|
|
Production and operating expenses
|
|
|
|
-
|
|
425
|
|
4
|
|
2,098
|
|
(
43)
|
|
2,484
|
|
Selling, general and administrative expenses
|
|
|
|
5
|
|
155
|
|
-
|
|
62
|
|
(
5)
|
|
217
|
|
Exploration expenses
|
|
|
|
-
|
|
91
|
|
-
|
|
73
|
|
-
|
|
164
|
|
Depreciation, depletion and amortization
|
|
|
|
-
|
|
275
|
|
-
|
|
2,575
|
|
-
|
|
2,850
|
|
Impairments
|
|
|
|
-
|
|
(
10)
|
|
-
|
|
(
13)
|
|
-
|
|
(
23)
|
|
Taxes other than income taxes
|
|
|
|
-
|
|
78
|
|
-
|
|
378
|
|
-
|
|
456
|
|
Accretion on discounted liabilities
|
|
|
|
-
|
|
9
|
|
-
|
|
168
|
|
-
|
|
177
|
|
Interest and debt expense
|
|
|
|
147
|
|
300
|
|
25
|
|
80
|
|
(
191)
|
|
361
|
|
Foreign currency transaction (gains) losses
|
|
|
|
34
|
|
(
9)
|
|
80
|
|
(
103)
|
|
-
|
|
2
|
|
Other expenses
|
|
|
|
-
|
|
342
|
|
6
|
|
(
8)
|
|
-
|
|
340
|
|
Total Costs and Expenses
|
|
|
|
186
|
|
8,347
|
|
115
|
|
7,871
|
|
(
2,713)
|
|
13,806
|
|
Income (Loss) before income taxes
|
|
|
|
2,492
|
|
2,713
|
|
777
|
|
5,182
|
|
(
6,769)
|
|
4,395
|
|
Income tax provision (benefit)
|
|
|
|
(
36)
|
|
54
|
|
(
19)
|
|
1,842
|
|
-
|
|
1,841
|
|
Net income (loss)
|
|
|
|
2,528
|
|
2,659
|
|
796
|
|
3,340
|
|
(
6,769)
|
|
2,554
|
|
Less: net income attributable to noncontrolling interests
|
|
|
|
-
|
|
-
|
|
-
|
|
(
26)
|
|
-
|
|
(
26)
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
$
|
2,528
|
|
2,659
|
|
796
|
|
3,314
|
|
(
6,769)
|
|
2,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss) Attributable to ConocoPhillips
|
|
|
$
|
2,351
|
|
2,482
|
|
537
|
|
3,042
|
|
(
6,061)
|
|
2,351
|
|
See Notes to Consolidated Financial Statements.
|
|
|
|
Millions of Dollars
|
|
|
|
June 30, 2019
|
|
Balance Sheet
|
ConocoPhillips
|
|
ConocoPhillips Company
|
|
Burlington Resources LLC
|
|
All Other Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
-
|
|
1,263
|
|
-
|
|
4,678
|
|
-
|
|
5,941
|
|
Short-term investments
|
|
-
|
|
50
|
|
-
|
|
682
|
|
-
|
|
732
|
|
Accounts and notes receivable
|
|
6
|
|
1,969
|
|
2
|
|
4,489
|
|
(
2,815)
|
|
3,651
|
|
Investment in Cenovus Energy
|
|
-
|
|
1,835
|
|
-
|
|
-
|
|
-
|
|
1,835
|
|
Inventories
|
|
-
|
|
152
|
|
-
|
|
937
|
|
-
|
|
1,089
|
|
Prepaid expenses and other current assets
|
|
1
|
|
173
|
|
-
|
|
2,378
|
|
-
|
|
2,552
|
|
Total Current Assets
|
|
7
|
|
5,442
|
|
2
|
|
13,164
|
|
(
2,815)
|
|
15,800
|
|
Investments, loans and long-term receivables*
|
|
32,085
|
|
49,325
|
|
16,544
|
|
15,592
|
|
(
104,530)
|
|
9,016
|
|
Net properties, plants and equipment
|
|
-
|
|
4,026
|
|
-
|
|
40,308
|
|
-
|
|
44,334
|
|
Other assets
|
|
4
|
|
852
|
|
228
|
|
1,936
|
|
(
909)
|
|
2,111
|
|
Total Assets
|
$
|
32,096
|
|
59,645
|
|
16,774
|
|
71,000
|
|
(
108,254)
|
|
71,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
-
|
|
2,909
|
|
-
|
|
3,541
|
|
(
2,815)
|
|
3,635
|
|
Short-term debt
|
|
(
3)
|
|
3
|
|
14
|
|
100
|
|
-
|
|
114
|
|
Accrued income and other taxes
|
|
-
|
|
61
|
|
-
|
|
1,152
|
|
-
|
|
1,213
|
|
Employee benefit obligations
|
|
-
|
|
405
|
|
-
|
|
124
|
|
-
|
|
529
|
|
Other accruals
|
|
85
|
|
632
|
|
35
|
|
2,753
|
|
-
|
|
3,505
|
|
Total Current Liabilities
|
|
82
|
|
4,010
|
|
49
|
|
7,670
|
|
(
2,815)
|
|
8,996
|
|
Long-term debt
|
|
3,792
|
|
6,672
|
|
2,136
|
|
2,209
|
|
-
|
|
14,809
|
|
Asset retirement obligations and accrued environmental costs
|
|
-
|
|
399
|
|
-
|
|
5,597
|
|
-
|
|
5,996
|
|
Deferred income taxes
|
|
-
|
|
-
|
|
-
|
|
5,733
|
|
(
908)
|
|
4,825
|
|
Employee benefit obligations
|
|
-
|
|
1,263
|
|
-
|
|
426
|
|
-
|
|
1,689
|
|
Other liabilities and deferred credits*
|
|
1,807
|
|
8,680
|
|
987
|
|
9,779
|
|
(
19,381)
|
|
1,872
|
|
Total Liabilities
|
|
5,681
|
|
21,024
|
|
3,172
|
|
31,414
|
|
(
23,104)
|
|
38,187
|
|
Retained earnings
|
|
30,271
|
|
20,440
|
|
2,085
|
|
9,573
|
|
(
25,600)
|
|
36,769
|
|
Other common stockholders’ equity
|
|
(
3,856)
|
|
18,181
|
|
11,517
|
|
29,915
|
|
(
59,550)
|
|
(
3,793)
|
|
Noncontrolling interests
|
|
-
|
|
-
|
|
-
|
|
98
|
|
-
|
|
98
|
|
Total Liabilities and Stockholders’ Equity
|
$
|
32,096
|
|
59,645
|
|
16,774
|
|
71,000
|
|
(
108,254)
|
|
71,261
|
|
*Includes intercompany loans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
-
|
|
1,428
|
|
-
|
|
4,487
|
|
-
|
|
5,915
|
|
Short-term investments
|
|
-
|
|
-
|
|
-
|
|
248
|
|
-
|
|
248
|
|
Accounts and notes receivable
|
|
28
|
|
5,646
|
|
78
|
|
6,707
|
|
(
8,392)
|
|
4,067
|
|
Investment in Cenovus Energy
|
|
-
|
|
1,462
|
|
-
|
|
-
|
|
-
|
|
1,462
|
|
Inventories
|
|
-
|
|
184
|
|
-
|
|
823
|
|
-
|
|
1,007
|
|
Prepaid expenses and other current assets
|
|
1
|
|
267
|
|
-
|
|
307
|
|
-
|
|
575
|
|
Total Current Assets
|
|
29
|
|
8,987
|
|
78
|
|
12,572
|
|
(
8,392)
|
|
13,274
|
|
Investments, loans and long-term receivables*
|
|
29,942
|
|
47,062
|
|
15,199
|
|
16,926
|
|
(
99,465)
|
|
9,664
|
|
Net properties, plants and equipment
|
|
-
|
|
4,367
|
|
-
|
|
41,796
|
|
(
465)
|
|
45,698
|
|
Other assets
|
|
4
|
|
642
|
|
227
|
|
1,269
|
|
(
798)
|
|
1,344
|
|
Total Assets
|
$
|
29,975
|
|
61,058
|
|
15,504
|
|
72,563
|
|
(
109,120)
|
|
69,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
-
|
|
5,098
|
|
76
|
|
7,113
|
|
(
8,392)
|
|
3,895
|
|
Short-term debt
|
|
(
3)
|
|
12
|
|
13
|
|
99
|
|
(
9)
|
|
112
|
|
Accrued income and other taxes
|
|
-
|
|
85
|
|
-
|
|
1,235
|
|
-
|
|
1,320
|
|
Employee benefit obligations
|
|
-
|
|
638
|
|
-
|
|
171
|
|
-
|
|
809
|
|
Other accruals
|
|
85
|
|
587
|
|
35
|
|
552
|
|
-
|
|
1,259
|
|
Total Current Liabilities
|
|
82
|
|
6,420
|
|
124
|
|
9,170
|
|
(
8,401)
|
|
7,395
|
|
Long-term debt
|
|
3,791
|
|
7,151
|
|
2,143
|
|
2,249
|
|
(
478)
|
|
14,856
|
|
Asset retirement obligations and accrued environmental costs
|
|
-
|
|
415
|
|
-
|
|
7,273
|
|
-
|
|
7,688
|
|
Deferred income taxes
|
|
-
|
|
-
|
|
-
|
|
5,819
|
|
(
798)
|
|
5,021
|
|
Employee benefit obligations
|
|
-
|
|
1,340
|
|
-
|
|
424
|
|
-
|
|
1,764
|
|
Other liabilities and deferred credits*
|
|
725
|
|
9,277
|
|
839
|
|
8,126
|
|
(
17,775)
|
|
1,192
|
|
Total Liabilities
|
|
4,598
|
|
24,603
|
|
3,106
|
|
33,061
|
|
(
27,452)
|
|
37,916
|
|
Retained earnings
|
|
27,512
|
|
18,511
|
|
1,113
|
|
9,764
|
|
(
22,890)
|
|
34,010
|
|
Other common stockholders’ equity
|
|
(
2,135)
|
|
17,944
|
|
11,285
|
|
29,613
|
|
(
58,778)
|
|
(
2,071)
|
|
Noncontrolling interests
|
|
-
|
|
-
|
|
-
|
|
125
|
|
-
|
|
125
|
|
Total Liabilities and Stockholders’ Equity
|
$
|
29,975
|
|
61,058
|
|
15,504
|
|
72,563
|
|
(
109,120)
|
|
69,980
|
|
*Includes intercompany loans.
See Notes to Consolidated Financial Statements.
|
|
|
|
|
|
Millions of Dollars
|
|
|
Six Months Ended June 30, 2019
|
|
Statement of Cash Flows
|
|
ConocoPhillips
|
|
ConocoPhillips Company
|
|
Burlington Resources LLC
|
|
All Other Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
$
|
1,571
|
|
5,125
|
|
(
40)
|
|
4,768
|
|
(
5,639)
|
|
5,785
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments
|
|
-
|
|
(
653)
|
|
-
|
|
(
2,882)
|
|
169
|
|
(
3,366)
|
|
Working capital changes associated with investing activities
|
|
-
|
|
41
|
|
-
|
|
(
17)
|
|
-
|
|
24
|
|
Proceeds from asset dispositions
|
|
-
|
|
142
|
|
-
|
|
559
|
|
-
|
|
701
|
|
Sales (purchases) of short-term investments
|
|
-
|
|
(
50)
|
|
-
|
|
(
435)
|
|
-
|
|
(
485)
|
|
Long-term advances/loans—related parties
|
|
-
|
|
(
19)
|
|
-
|
|
-
|
|
19
|
|
-
|
|
Collection of advances/loans—related parties
|
|
-
|
|
69
|
|
-
|
|
82
|
|
(
89)
|
|
62
|
|
Intercompany cash management
|
|
1,082
|
|
(
3,256)
|
|
40
|
|
2,134
|
|
-
|
|
-
|
|
Other
|
|
-
|
|
118
|
|
-
|
|
8
|
|
-
|
|
126
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
1,082
|
|
(
3,608)
|
|
40
|
|
(
551)
|
|
99
|
|
(
2,938)
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
-
|
|
-
|
|
-
|
|
19
|
|
(
19)
|
|
-
|
|
Repayment of debt
|
|
-
|
|
(
21)
|
|
-
|
|
(
106)
|
|
89
|
|
(
38)
|
|
Issuance of company common stock
|
|
43
|
|
-
|
|
-
|
|
-
|
|
(
79)
|
|
(
36)
|
|
Repurchase of company common stock
|
|
(
2,002)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(
2,002)
|
|
Dividends paid
|
|
(
696)
|
|
(
1,660)
|
|
-
|
|
(
3,983)
|
|
5,643
|
|
(
696)
|
|
Other
|
|
2
|
|
-
|
|
-
|
|
37
|
|
(
94)
|
|
(
55)
|
|
Net Cash Provided by (Used in) Financing Activities
|
|
(
2,653)
|
|
(
1,681)
|
|
-
|
|
(
4,033)
|
|
5,540
|
|
(
2,827)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
|
|
-
|
|
(
1)
|
|
-
|
|
27
|
|
-
|
|
26
|
|
|
|
Net Change in Cash, Cash Equivalents and Restricted Cash
|
|
-
|
|
(
165)
|
|
-
|
|
211
|
|
-
|
|
46
|
|
Cash, cash equivalents and restricted cash at beginning of period*
|
|
-
|
|
1,428
|
|
-
|
|
4,723
|
|
-
|
|
6,151
|
|
Cash, Cash Equivalents and Restricted Cash at End of Period
|
$
|
-
|
|
1,263
|
|
-
|
|
4,934
|
|
-
|
|
6,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows
|
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
$
|
2,417
|
|
519
|
|
2,467
|
|
5,682
|
|
(
5,344)
|
|
5,741
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments
|
|
-
|
|
(
507)
|
|
-
|
|
(
3,034)
|
|
7
|
|
(
3,534)
|
|
Working capital changes associated with investing activities
|
|
-
|
|
(
116)
|
|
-
|
|
24
|
|
-
|
|
(
92)
|
|
Proceeds from asset dispositions
|
|
-
|
|
274
|
|
-
|
|
146
|
|
(
112)
|
|
308
|
|
Sales of short-term investments
|
|
-
|
|
-
|
|
-
|
|
1,257
|
|
-
|
|
1,257
|
|
Long-term advances/loans—related parties
|
|
-
|
|
(
8)
|
|
(
87)
|
|
-
|
|
95
|
|
-
|
|
Collection of advances/loans—related parties
|
|
-
|
|
2,500
|
|
-
|
|
59
|
|
(
2,500)
|
|
59
|
|
Intercompany cash management
|
|
(
721)
|
|
4,517
|
|
(
2,328)
|
|
(
1,468)
|
|
-
|
|
-
|
|
Other
|
|
-
|
|
2
|
|
-
|
|
(
27)
|
|
-
|
|
(
25)
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
(
721)
|
|
6,662
|
|
(
2,415)
|
|
(
3,043)
|
|
(
2,510)
|
|
(
2,027)
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
-
|
|
-
|
|
-
|
|
95
|
|
(
95)
|
|
-
|
|
Repayment of debt
|
|
-
|
|
(
4,855)
|
|
(
53)
|
|
(
2,544)
|
|
2,500
|
|
(
4,952)
|
|
Issuance of company common stock
|
|
123
|
|
-
|
|
-
|
|
-
|
|
(
81)
|
|
42
|
|
Repurchase of company common stock
|
|
(
1,146)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(
1,146)
|
|
Dividends paid
|
|
(
675)
|
|
-
|
|
-
|
|
(
1,217)
|
|
1,217
|
|
(
675)
|
|
Other
|
|
2
|
|
(
2,511)
|
|
-
|
|
(
1,852)
|
|
4,313
|
|
(
48)
|
|
Net Cash Used in Financing Activities
|
|
(
1,696)
|
|
(
7,366)
|
|
(
53)
|
|
(
5,518)
|
|
7,854
|
|
(
6,779)
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
-
|
|
4
|
|
-
|
|
(
18)
|
|
-
|
|
(
14)
|
|
|
|
Net Change in Cash and Cash Equivalents
|
|
-
|
|
(
181)
|
|
(
1)
|
|
(
2,897)
|
|
-
|
|
(
3,079)
|
|
Cash and cash equivalents at beginning of period
|
|
-
|
|
234
|
|
3
|
|
6,299
|
|
-
|
|
6,536
|
|
Cash and Cash Equivalents at End of Period
|
$
|
-
|
|
53
|
|
2
|
|
3,402
|
|
-
|
|
3,457
|
|
See Notes to Consolidated Financial Statements.
|
Item 2.
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. 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
62.
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 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, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe and North Africa, Asia and Australia; LNG developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. At June 30, 2019, we employed approximately 10,900 people worldwide and had total assets of $71 billion.
Overview
Global oil prices have been volatile in 2019. Optimism about worldwide economic growth during the first quarter turned to pessimism in the second quarter as trade disputes dampened growth forecasts. At the end of the second quarter, geopolitical tensions in the Middle East, threatening the safe passage of supertankers carrying crude oil through the Persian Gulf, have revived oil prices. Our business strategy anticipates prices will remain volatile and is designed to be resilient in lower price environments, with significant upside during periods of higher prices. Portfolio diversification and optimization, debt reduction and disciplined capital investment have positioned our company to navigate through periods of volatile energy prices.
Our value proposition principles, namely, to focus on returns, maintain financial strength, grow our dividend and pursue disciplined growth, are being executed in accordance with our priorities for allocating cash flows from the business. These priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; maintain debt at a level we believe is sufficient to maintain a strong investment grade credit rating through price cycles; repurchase shares to provide value to our shareholders; and invest capital to grow our cash from operations. We believe our commitment to our value proposition, as evidenced by the results discussed below, position us for success in an environment of price uncertainty and ongoing volatility.
In the second quarter of 2019, we continued to deliver on our priorities. We achieved production growth of 7 percent on a total BOE basis compared with the second quarter of 2018, with higher value oil volumes growing 12 percent. Cash provided by operating activities of $2.9 billion exceeded capital expenditures and investments of $1.7 billion. After distributing $0.3 billion of dividends to shareholders and repurchasing $1.2 billion of our common stock, we ended the quarter with cash, cash equivalents and restricted cash totaling $6.2 billion and $0.7 billion of short-term investments. Additionally, in July we announced an increase to our
expected full-year 2019 share repurchases to $3.5 billion, an increase of $0.5 billion from previously stated plans.
Operationally, we remain focused on safely executing our operating plan and staying attentive to our costs. Production excluding Libya was 1,290 MBOED in the second quarter of 2019, an increase of 79 MBOED compared with the same period of 2018. Our underlying production, which excludes Libya and the additional volumes from closed 2018 acquisitions and dispositions of approximately 27 MBOED, increased 4 percent compared with the second quarter of 2018. Production on a per debt-adjusted share basis grew by 6 percent compared with the second quarter of 2018. 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 comparison across peer companies.
In the second quarter of 2019, we completed the sale of our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million, before customary adjustments, and recognized an after-tax gain of $52 million. No production or reserve impacts are associated with the sale. Proceeds from this transaction will be used for general corporate purposes. The Greater Sunrise Fields are included in our Asia Pacific and Middle East segment.
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, subject to regulatory approval and other specific conditions precedent. Together the subsidiaries indirectly hold the company’s E&P assets in the U.K. As a result of entering into the transaction agreement, we recognized a U.S. tax benefit of $234 million in the second quarter of 2019 related to the recognition of U.S. tax basis in our U.K. subsidiaries to be sold. Depending on the timing of regulatory approval and satisfaction of conditions precedent, we anticipate recognizing an additional gain of approximately $2 billion before- and after-tax on completion of the sale in the second half of 2019, subject to customary adjustments and foreign exchange impacts. Full-year 2018 production and year-end 2018 proved reserves associated with the U.K. assets being sold were approximately 72 MBOED and approximately 99 MMBOE, respectively. Results of operations for the U.K. are reported within our Europe and North Africa segment. See Note 5—Assets Held for Sale and Dispositions in the Notes to Consolidated Financial Statements, for additional information.
Business Environment
Dated Brent crude oil prices have ranged from a low of $53 per barrel to a high of $75 per barrel in the first half of 2019. The energy industry has periodically experienced volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC, environmental laws, tax regulations, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.
Our earnings and operating cash flows generally correlate with industry price levels for crude oil and natural gas, the prices of which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for WTI crude oil, Dated Brent crude oil and Henry Hub natural gas:
Brent crude oil prices averaged $68.82 per barrel in the second quarter of 2019, a decrease of 7 percent compared with $74.35 per barrel in the second quarter of 2018, and an increase of 9 percent compared with $63.20 per barrel in the first quarter of 2019. Crude oil prices for WTI averaged $59.80 per barrel in the second quarter of 2019, a decrease of 12 percent compared with $67.99 per barrel in the second quarter of 2018, and an increase of 9 percent compared with $54.87 per barrel in the first quarter of 2019. Prices decreased relative to the same period a year ago due to concerns about inventory levels and demand growth.
Henry Hub natural gas prices averaged $2.64 per MMBTU in the second quarter of 2019, a decrease of 6 percent compared with $2.80 per MMBTU in the second quarter of 2018, and a decrease of 16 percent compared with $3.15 per MMBTU in the first quarter of 2019. Prices decreased relative to the same period of 2018 due to seasonally mild weather reducing demand and increasing natural gas production in the contiguous United States.
Our realized bitumen price increased from $32.38 per barrel in the second quarter of 2018 to $37.20 per barrel in the same period of 2019, primarily due to lower diluent costs and improvements in the WCS differential to WTI at Hardisty, which offset declines in the WTI benchmark price. Compared with $33.15 per barrel in the first quarter of 2019, our second quarter 2019 realized bitumen price increased due to improvements in the WTI benchmark price and continued strength in the WCS differential to WTI at Hardisty. The WCS differential to WTI at Hardisty decreased in the second quarter of 2019, compared to the first quarter of 2019, due to a continuation of curtailment orders in conjunction with upstream turnarounds.
Our total average realized price was $50.50 per BOE in the second quarter of 2019, compared with $54.32 per BOE in the second quarter of 2018 due to lower realized oil, natural gas and NGL prices.
Key Operating and Financial Summary
Significant items during the second quarter of 2019 included the following:
Cash provided by operating activities was $2.9 billion and exceeded capital expenditures and investments of $1.7 billion.
Increased 2019 planned share repurchases to $3.5 billion.
Repurchased $1.2 billion of shares and paid $0.3 billion in dividends.
Second-quarter production excluding Libya of 1,290 MBOED; year-over-year underlying production grew 4 percent overall and 6 percent on a production per debt-adjusted share basis.
Grew production from the Lower 48 Big 3 unconventional plays—Eagle Ford, Bakken and Delaware—by 26 percent year-over-year.
Executed turnarounds in Europe, Canada and Alaska.
Ended the quarter with cash, cash equivalents and restricted cash totaling $6.2 billion and short-term investments of $0.7 billion.
Generated $0.6 billion in proceeds from dispositions.
Acquired approximately $0.1 billion in Lower 48 Big 3 bolt-on interests and acreage.
Outlook
Production and Capital Guidance
Third-quarter 2019 production is expected to be 1,290 to 1,330 MBOED, reflecting planned turnarounds in Alaska, Europe and Asia Pacific. Full-year 2019 production guidance is 1,310 to 1,340 MBOED. This guidance excludes Libya.
Capital expenditures are now expected to be $6.3 billion versus $6.1 billion, attributable to additional exploration and appraisal drilling in Alaska and the addition of a drilling rig in the Eagle Ford at mid-year 2019. This guidance excludes approximately $0.3 billion for opportunistic acquisitions completed or announced and results in total capital expenditures and investments of $6.6 billion. Guidance also excludes obligations under the recently announced production sharing contract extension awarded by the Government of Indonesia.
Production and capital guidance will be revised following the planned U.K. disposition closing.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 2019, is based on a comparison with the corresponding periods of 2018.
Consolidated Results
A summary of the company's net income attributable to ConocoPhillips by business segment follows:
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
$
|
462
|
|
418
|
|
846
|
|
942
|
|
Lower 48
|
|
206
|
|
410
|
|
399
|
|
718
|
|
Canada
|
|
100
|
|
33
|
|
222
|
|
(32)
|
|
Europe and North Africa
|
|
407
|
|
290
|
|
614
|
|
535
|
|
Asia Pacific and Middle East
|
|
517
|
|
466
|
|
1,042
|
|
927
|
|
Other International
|
|
81
|
|
(5)
|
|
212
|
|
(49)
|
|
Corporate and Other
|
|
(193)
|
|
28
|
|
78
|
|
(513)
|
|
Net income attributable to ConocoPhillips
|
$
|
1,580
|
|
1,640
|
|
3,413
|
|
2,528
|
Net income attributable to ConocoPhillips in the second quarter of 2019 decreased $60 million. Earnings were negatively impacted by:
Lower realized crude oil, NGL and natural gas prices.
A $312 million lower after-tax unrealized gain on our Cenovus Energy common shares reflected in other income as compared to the second quarter of 2018.
Higher production and operating expenses associated with increased production volumes, primarily in the Lower 48 and Alaska, and increased legal accruals in our Lower 48 and Other International segments.
Lower equity in earnings of affiliates, primarily due to a $73 million after-tax impairment of our investment in the Marine Well Containment Company (MWCC) in our Lower 48 segment.
Second quarter 2019 net income decreases were partly offset by:
Higher crude oil sales volumes due to growth in the Lower 48 unconventionals and the acquisition of incremental interests from operated assets in Alaska during the second and fourth quarters of 2018.
A $234 million U.S. tax benefit related to the recognition of U.S. tax basis in our U.K. subsidiaries classified as held for sale.
The absence of a $121 million after-tax charge to pension settlement expense recorded in the second quarter of 2018.
Increased earnings of $115 million related to the settlement of certain tax disputes and enhanced oil recovery credits.
Other income of $84 million after-tax related to our settlement agreement with Petróleos de Venezuela, S.A. (PDVSA).
Net income attributable to ConocoPhillips in the six-month period ended June 30, 2019, increased $885 million. Earnings were positively impacted by:
Higher crude oil sales volumes due to growth in the Lower 48 unconventionals and the acquisition of incremental interests from operated assets in Alaska during the second and fourth quarters of 2018.
A $234 million U.S. tax benefit related to the recognition of U.S. tax basis in our U.K. subsidiaries classified as held for sale.
Other income of $231 million after-tax related to our settlement agreement with PDVSA.
The absence of premiums on debt retirements totaling $195 million after-tax recognized primarily in the first quarter of 2018.
A $154 million higher after-tax unrealized gain on our Cenovus Energy common shares reflected in other income.
The absence of a $121 million after-tax charge to pension settlement expense recorded in the second quarter of 2018.
Increased earnings of $115 million related to the settlement of certain tax disputes and enhanced oil recovery credits.
Earnings in the six-month period ended June 30, 2019, were negatively impacted by:
Lower realized crude oil, NGL and natural gas prices.
Higher DD&A associated with increased production volumes, primarily in the Lower 48 and Alaska.
Higher production and operating expenses associated with increased production volumes, primarily in the Lower 48 and Alaska, and increased legal accruals in our Lower 48 and Other International segments.
Lower equity in earnings of affiliates, primarily due to impairments of equity method investments in our Lower 48 segment of $120 million after-tax in 2019.
The absence of a $109 million after-tax benefit from an accrual reduction related to a transportation cost ruling by the FERC, recorded in the first quarter of 2018.
See the “Segment Results” section for additional information.
Income Statement Analysis
Sales and other operating revenues
for the second quarter of 2019 decreased 6 percent, mainly due to lower realized crude oil, NGL and natural gas prices, partly offset by higher sales volumes of crude oil in the Lower 48 and Alaska.
Equity in earnings of affiliates
for the three- and six-month periods of 2019 decreased 35 percent and 24 percent, respectively, primarily due to impairments of equity method investments in our Lower 48 segment of $95 million in the second quarter of 2019 and $60 million in the first quarter of 2019. For more information, see Note 5—Assets Held for Sale and Dispositions and Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements.
Other income
for the second quarter of 2019 decreased $244 million, primarily due to a $353 million before-tax lower unrealized gain on our Cenovus Energy common shares as compared to the second quarter of 2018. Partly offsetting this decrease was $89 million before-tax related to our settlement agreement with PDVSA. Other income in the six-month period of 2019 increased $510 million, due to the recognition of $236 million before-tax related to our settlement agreement with PDVSA as well as a $113 million before-tax higher unrealized gain on our Cenovus Energy common shares compared to the same period of 2018.
For discussion of our Cenovus Energy shares, see Note 7—Investment in Cenovus Energy, in the Notes to Consolidated Financial Statements. For discussion of our PDVSA settlement, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Purchased commodities
for the three- and six-month periods of 2019 decreased 13 and 6 percent, respectively, primarily due to lower crude oil and natural gas prices.
Production and operating expenses
for the three- and six-month periods of 2019 increased $105 million and $205 million, respectively, mainly due to costs associated with higher production volumes, primarily in the Lower 48 and Alaska, and increased legal accruals in our Lower 48 and Other International segments.
DD&A
for the three- and six-month periods of 2019 increased 4 percent and 7 percent, respectively, mainly due to higher production volumes in the Lower 48 and Alaska, partly offset by lower expense in our Europe and North Africa segment due to the cessation of DD&A on the assets held-for-sale associated with our planned U.K. divestiture. For more information regarding the planned U.K. divestiture, see Note 5—Assets Held for Sale and Dispositions.
Other expenses
decreased $129 million and $318 million in the three- and six-month periods of 2019, respectively, primarily due to the absence of a $206 million before-tax expense for premiums on early debt retirements in the first quarter of 2018 and the absence of a $147 million before-tax charge to pension settlement expense recorded in the second quarter of 2018.
See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit)
and effective tax rate.
|
Summary Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
702
|
|
624
|
|
708
|
|
630
|
|
Natural gas liquids (MBD)
|
|
118
|
|
103
|
|
114
|
|
99
|
|
Bitumen (MBD)
|
|
51
|
|
63
|
|
57
|
|
64
|
|
Natural gas (MMCFD)*
|
|
2,768
|
|
2,754
|
|
2,804
|
|
2,791
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
1,332
|
|
1,249
|
|
1,346
|
|
1,258
|
|
|
|
|
|
|
|
|
|
Dollars Per Unit
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude oil (per barrel)
|
|
64.88
|
|
70.55
|
|
62.14
|
|
68.00
|
|
Natural gas liquids (per barrel)
|
|
21.65
|
|
29.94
|
|
22.71
|
|
29.20
|
|
Bitumen (per barrel)
|
|
37.20
|
|
32.38
|
|
35.00
|
|
22.75
|
|
Natural gas (per thousand cubic feet)
|
|
4.76
|
|
5.18
|
|
5.39
|
|
5.16
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
Exploration Expenses
|
|
|
|
|
|
|
|
|
|
General administrative, geological and geophysical,
|
|
|
|
|
|
|
|
|
|
|
lease rental, and other
|
$
|
81
|
|
53
|
|
164
|
|
128
|
|
Leasehold impairment
|
|
25
|
|
15
|
|
42
|
|
20
|
|
Dry holes
|
|
16
|
|
1
|
|
26
|
|
16
|
|
|
|
$
|
122
|
|
69
|
|
232
|
|
164
|
|
*Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.
|
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. At June 30, 2019, our operations were producing in the U.S., Norway, the U.K., Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.
Total production increased 83 MBOED or 7 percent in the second quarter of 2019, primarily due to:
New wells online in the Lower 48.
An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following acquisitions closed in 2018.
Higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December 2018.
Lower unplanned downtime, primarily in Malaysia, Canada and the U.K.
The increase in second quarter 2019 production was partly offset by:
Normal field decline.
Planned turnarounds at Surmont in Canada, the Greater Ekofisk Area in Norway and J-Area in the U.K.
Disposition impacts from non-core asset sales in the Lower 48 and the sale of a ConocoPhillips subsidiary holding 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the U.K. during 2018.
Total production increased 88 MBOED or 7 percent in the six-month period of 2019, primarily due to:
New wells online in the Lower 48.
An increased interest in the WNS and GKA of Alaska following acquisitions closed in 2018.
Higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December 2018.
The increase in production during the six-month period of 2019 was partly offset by:
Normal field decline.
Disposition impacts from non-core asset sales in the Lower 48 and the sale of a ConocoPhillips subsidiary holding 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the U.K. during 2018.
Planned turnarounds at QG3 in Qatar, the Greater Ekofisk Area in Norway and Surmont in Canada.
Production excluding Libya was 1,290 MBOED in the second quarter of 2019, an increase of 79 MBOED or 7 percent compared with the same period of 2018. Our underlying production, which excludes Libya and the additional volumes from closed 2018 acquisitions and dispositions of 27 MBOED, increased 4 percent compared with the second quarter of 2018.
Production excluding Libya was 1,303 MBOED in the six-month period of 2019, an increase of 87 MBOED or 7 percent compared with the same period of 2018. Our underlying production in the six-month period of 2019, which excludes Libya and the additional volumes from closed 2018 acquisitions and dispositions of 28 MBOED, increased 5 percent compared with the same period of 2018.
|
Segment Results
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
462
|
|
418
|
|
846
|
|
942
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
199
|
|
170
|
|
205
|
|
172
|
|
Natural gas liquids (MBD)
|
|
17
|
|
14
|
|
17
|
|
15
|
|
Natural gas (MMCFD)
|
|
7
|
|
6
|
|
7
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
217
|
|
185
|
|
223
|
|
188
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude oil (dollars per barrel)
|
$
|
67.57
|
|
72.49
|
|
65.11
|
|
70.34
|
|
Natural gas (dollars per thousand cubic feet)
|
|
3.19
|
|
2.51
|
|
3.31
|
|
2.51
|
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of June 30, 2019, Alaska contributed 25 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.
Earnings from Alaska for the second quarter of 2019 increased $44 million compared with the corresponding period of 2018, primarily because of higher crude oil sales volumes due to increased interests in the WNS and GKA following acquisitions completed in the second and fourth quarters of 2018, respectively. Additionally, earnings increased due to $81 million of tax benefits related to the settlement of certain tax disputes and enhanced oil recovery credits. Partly offsetting the increase in earnings were lower realized crude oil prices and higher production and operating expenses associated with higher sales volumes.
Earnings from Alaska for the six-month period of 2019 decreased $96 million compared with the corresponding period of 2018, primarily because of lower realized crude oil prices, higher production and operating expenses associated with higher volumes, and the absence of a $79 million after-tax benefit resulting from an accrual reduction due to a transportation cost ruling by the FERC, recorded in the first quarter of 2018. Partly offsetting the decrease in earnings was higher crude oil sales volumes due to increased interests in the WNS and GKA following acquisitions completed in 2018 and tax benefits of $81 million related to the settlement of certain tax disputes and enhanced oil recovery credits.
Average production was up 32 MBOED and 35 MBOED in the three- and six-month periods of 2019 compared with the corresponding periods of 2018. The increases were primarily due to acquiring incremental interests in the WNS and GKA in 2018, which contributed 43 MBOED and 45 MBOED in the three- and six-month periods of 2019, respectively. Production also increased due to the rampup of Greater Mooses Tooth #1 following first oil in the fourth quarter of 2018, partly offset by normal field decline.
Exploration Update
In June 2019, we entered into an agreement with Caelus Natural Resources Alaska, LLC to acquire Nuna acreage adjacent to our Kuparuk Field. We expect the transaction to close in the third quarter of 2019, subject to state regulatory approval.
|
Lower 48
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
206
|
|
410
|
|
399
|
|
718
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
269
|
|
218
|
|
257
|
|
207
|
|
Natural gas liquids (MBD)
|
|
82
|
|
70
|
|
78
|
|
65
|
|
Natural gas (MMCFD)
|
|
593
|
|
593
|
|
581
|
|
580
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
450
|
|
387
|
|
432
|
|
369
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude oil (dollars per barrel)
|
$
|
59.17
|
|
65.79
|
|
56.31
|
|
64.00
|
|
Natural gas liquids (dollars per barrel)
|
|
17.91
|
|
26.71
|
|
19.20
|
|
25.73
|
|
Natural gas (dollars per thousand cubic feet)
|
|
2.10
|
|
2.34
|
|
2.41
|
|
2.54
|
The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties in the Gulf of Mexico. As of June 30, 2019, the Lower 48 contributed 38 percent of our worldwide liquids production and 21 percent of our worldwide natural gas production.
Earnings from the Lower 48 for the three- and six-month periods of 2019 decreased $204 million and $319 million, respectively, compared with corresponding periods in 2018, primarily due to lower realized crude oil and NGL prices; higher DD&A associated with increased production volumes; higher production and operating expenses due to increased legal accruals as well as higher production volumes; and lower earnings in equity of affiliates. Earnings in equity affiliates were reduced due to a $47 million after-tax impairment associated with the sale of our interests in the Golden Pass LNG Terminal and Golden Pass Pipeline in the first quarter of 2019 and a $73 million after-tax impairment associated with our investment in the MWCC in the second quarter of 2019. Partly offsetting the decrease in earnings was increased crude oil and NGL volumes in the Eagle Ford, Bakken and Delaware in the Permian Basin.
For additional information related to our impairment of MWCC, see Note 3—Variable Interest Entities in the Notes to Consolidated Financial Statements. For more information related to the sale of our interests in Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Assets Held for Sale and Dispositions and Note 14—Fair Value Measurement.
Total average production increased 63 MBOED in both the three- and six-month periods of 2019, compared with the same periods of 2018, primarily due to new production from unconventional assets in Eagle Ford, Bakken and Delaware in the Permian Basin. Partly offsetting the increase in production was normal field decline and the impact of non-core dispositions in 2018, which decreased production by 13 MBOED and 12 MBOED in the three- and six-month periods of 2019, respectively.
Asset Disposition Update
In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass LNG Terminal and Golden Pass Pipeline. We have also entered into agreements to amend our contractual obligations for retaining use of the facilities. As a result of entering into these agreements, we recognized a before-tax impairment of $60 million in the first quarter of 2019 which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. In the second quarter of 2019, we completed the sale.
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
100
|
|
33
|
|
222
|
|
(32)
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
1
|
|
1
|
|
1
|
|
2
|
|
Natural gas liquids (MBD)
|
|
1
|
|
-
|
|
-
|
|
-
|
|
Bitumen (MBD)
|
|
51
|
|
63
|
|
57
|
|
64
|
|
Natural gas (MMCFD)
|
|
8
|
|
14
|
|
8
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
54
|
|
67
|
|
59
|
|
68
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Bitumen (dollars per barrel)*
|
|
37.20
|
|
32.38
|
|
35.00
|
|
22.75
|
|
*Average prices for sales of bitumen excludes additional value realized from the purchase and sale of third-party volumes
for optimization of our pipeline capacity between Canada and the U.S. Gulf Coast.
|
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. As of June 30, 2019, Canada contributed 7 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.
Earnings from Canada increased $67 million in the second quarter of 2019, compared with the corresponding period of 2018, primarily because of lower DD&A expense, due to lower rates from reserve additions and decreased sales volumes; a $25 million tax benefit due to a four year phased four percent reduction in Alberta’s corporate income tax rate and higher bitumen realizations; partly offset by lower sales volumes. Earnings increased $254 million in the six-month period of 2019, compared with the corresponding period of 2018, mainly due to higher realized bitumen prices and a $68 million tax benefit primarily comprised of a previously unrecognizable tax basis related to a tax settlement, partly offset by lower sales volumes.
Total average production decreased 13 MBOED in the second quarter of 2019, compared with the same period of 2018, primarily due to a planned turnaround at Surmont, which impacted bitumen production by 12 MBOED. Total average production decreased 9 MBOED in the six-month period of 2019, compared with the same period of 2018, primarily due to a 6 MBOED impact from a planned turnaround in Surmont and 4 MBOED related to a mandated production curtailment imposed by the Alberta government in January 2019. The curtailment measure is intended to strengthen the WCS differential to WTI at Hardisty and is anticipated to be temporary.
|
Europe and North Africa
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30
|
June 30
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
407
|
|
290
|
|
614
|
|
535
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
130
|
|
139
|
|
141
|
|
148
|
|
Natural gas liquids (MBD)
|
|
6
|
|
8
|
|
8
|
|
8
|
|
Natural gas (MMCFD)
|
|
518
|
|
507
|
|
560
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
223
|
|
230
|
|
242
|
|
244
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude oil (dollars per barrel)
|
$
|
69.65
|
|
72.65
|
|
66.16
|
|
69.07
|
|
Natural gas liquids (dollars per barrel)
|
|
32.00
|
|
40.35
|
|
31.49
|
|
37.38
|
|
Natural gas (dollars per thousand cubic feet)
|
|
4.42
|
|
7.19
|
|
5.58
|
|
7.29
|
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. As of June 30, 2019, our Europe and North Africa operations contributed 17 percent of our worldwide liquids production and 20 percent of our worldwide natural gas production.
Earnings for Europe and North Africa increased by $117 million and $79 million in the three- and six-month periods of 2019, respectively, compared with the same periods of 2018. The earnings increase in both periods was mainly due to a U.S. tax benefit of $234 million, recorded in the second quarter of 2019, primarily related to the recognition of U.S. tax basis in our U.K. subsidiaries classified as held for sale. Earnings in both periods also increased due to the cessation of DD&A on the assets held-for-sale associated with our planned U.K. disposition. Partly offsetting the increase in earnings, were lower realized natural gas and crude oil prices and lower sales volumes.
Average production decreased 3 percent and 1 percent in the three- and six-month periods of 2019, respectively, compared with the same periods of 2018, primarily due to normal field decline, and planned turnarounds in the second quarter of 2019 in the Greater Ekofisk Area in Norway and J-Area in the U.K. Partly offsetting the production decrease, were increases from new wells online in Norway and the U.K., including the rampup of production at Aasta Hansteen in Norway.
Asset Disposition Update
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, subject to regulatory approval and other specific conditions precedent. Together the subsidiaries indirectly hold the company’s E&P assets in the U.K. As part of the transaction, we recognized a U.S. tax benefit of $234 million, recorded in the second quarter of 2019, primarily related to the recognition of U.S. tax basis in our U.K. subsidiaries classified as held for sale. Depending on the timing of regulatory approval and satisfaction of other conditions precedent, we anticipate recognizing an additional gain of approximately $2 billion before- and after-tax on completion of the sale in the second half of 2019, subject to customary adjustments and foreign exchange impacts. Full-year 2018 production and year-end 2018 proved reserves associated with the U.K. assets being sold were approximately 72 MBOED and approximately 99 MMBOE, respectively. See Note 5—Assets Held for Sale and Dispositions in the Notes to Consolidated Financial Statements, for additional information.
|
Asia Pacific and Middle East
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
517
|
|
466
|
|
1,042
|
|
927
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production
|
|
|
|
|
|
|
|
|
|
Crude oil (MBD)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
89
|
|
82
|
|
91
|
|
87
|
|
|
Equity affiliates
|
|
14
|
|
14
|
|
13
|
|
14
|
|
|
Total crude oil
|
|
103
|
|
96
|
|
104
|
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids (MBD)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
4
|
|
3
|
|
4
|
|
3
|
|
|
Equity affiliates
|
|
8
|
|
8
|
|
7
|
|
8
|
|
|
Total natural gas liquids
|
|
12
|
|
11
|
|
11
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCFD)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
578
|
|
580
|
|
622
|
|
609
|
|
|
Equity affiliates
|
|
1,064
|
|
1,054
|
|
1,026
|
|
1,053
|
|
|
Total natural gas
|
|
1,642
|
|
1,634
|
|
1,648
|
|
1,662
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOED)
|
|
388
|
|
380
|
|
390
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude oil (dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
$
|
69.78
|
|
74.88
|
|
65.93
|
|
70.51
|
|
|
Equity affiliates
|
|
63.98
|
|
76.11
|
|
61.94
|
|
71.24
|
|
|
Total crude oil
|
|
68.91
|
|
75.08
|
|
65.43
|
|
70.61
|
|
Natural gas liquids (dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
39.97
|
|
44.23
|
|
40.05
|
|
44.34
|
|
|
Equity affiliates
|
|
41.72
|
|
43.60
|
|
40.09
|
|
43.79
|
|
|
Total natural gas liquids
|
|
41.05
|
|
43.65
|
|
40.07
|
|
43.93
|
|
Natural gas (dollars per thousand cubic feet)
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
5.89
|
|
5.50
|
|
6.14
|
|
5.53
|
|
|
Equity affiliates
|
|
5.81
|
|
5.72
|
|
6.53
|
|
5.37
|
|
|
Total natural gas
|
|
5.84
|
|
5.64
|
|
6.38
|
|
5.43
|
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. As of June 30, 2019, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 59 percent of our worldwide natural gas production.
Earnings increased $51 million in the second quarter of 2019 compared with the same period of 2018, primarily due to a $52 million after-tax gain on disposition of our interest in the Greater Sunrise Fields and higher crude oil, LNG and NGL sales volumes, partly offset by lower realizations for crude oil and LNG. Earnings increased $115 million in the six-month period of 2019, compared with the same period of 2018, primarily due to higher realized LNG prices and a $52 million after-tax gain on disposition of our interest in the Greater Sunrise Fields, partly offset by lower crude oil realizations.
Average production increased 8 MBOED in the second quarter of 2019, compared with the corresponding period of 2018, primarily because of lower planned downtime at Darwin LNG and Bayu Undan in Australia and Timor-Leste, new production from Bayu Undan and China, and less unplanned downtime at the Kebabangan gas field in Malaysia. Partly offsetting these increases was normal field decline. Average production increased 1 MBOED in the six-month period of 2019, compared with the same period of 2018, primarily due to new production from China and Bayu Undan, offset by normal field decline.
Asset Disposition Update
In the second quarter of 2019, we recognized an after-tax gain of $52 million upon completion of the sale of our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million, before customary adjustments. No production or reserve impacts were associated with the sale.
Deepwater Incentive Tax Credits
In July 2019, all partners in the Malaysia Block G PSC approved claiming certain deepwater incentive tax credits. As a result, we expect to recognize an income tax benefit in the third quarter of 2019 of approximately $165 million.
|
Other International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
(millions of dollars)
|
$
|
81
|
|
(5)
|
|
212
|
|
(49)
|
The Other International segment consists of exploration activities in Colombia, Chile and Argentina.
Earnings from our Other International operations increased $86 million and $261 million in the three- and six-month periods of 2019, compared with the same periods of 2018. The increase was primarily due to recognizing $84 million and $231 million in other income related to a settlement award with PDVSA associated with prior operations in Venezuela, in the three- and six-month periods of 2019, respectively. See Note 12—Contingencies and Commitments in the Notes to Consolidated Financial Statements, for additional information.
Exploration Update
In July 2019, we entered into an agreement with Wintershall Dea to jointly develop the Aguada Federal and Bandurria Norte blocks in the central Argentine province of Neuquén. As part of the transaction, we will acquire a 45 percent interest in the Aguada Federal Block situated in the Neuquén Basin, Wintershall Dea will retain a 45 percent interest as operator, and the remaining 10 percent interest is held by Gas y Petroleo del Neuquen S.A. (GyP). In the nearby Bandurria Norte Block, we will acquire a 50 percent interest, with Wintershall Dea retaining the other 50 percent as operator. This transaction is expected to close in 2019, subject to approval by the relevant authorities.
|
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30
|
June 30
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
|
Net interest
|
$
|
(131)
|
|
(174)
|
|
(327)
|
|
(334)
|
|
|
Corporate general and administrative expenses
|
|
(49)
|
|
(53)
|
|
(114)
|
|
(103)
|
|
|
Technology
|
|
(10)
|
|
63
|
|
86
|
|
53
|
|
|
Other
|
|
(3)
|
|
192
|
|
433
|
|
(129)
|
|
|
|
$
|
(193)
|
|
28
|
|
78
|
|
(513)
|
|
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest decreased by $43 million in the second quarter of 2019, primarily due to lower interest from the settlement of certain tax disputes. In the six-month period of 2019, net interest decreased by $7 million, primarily due to lower interest from the previously mentioned settlement, partly offset by higher interest from the absence of an accrual reduction related to a transportation cost ruling by the FERC in the first quarter of 2018.
Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $4 million and increased by $11 million in the three- and six-month periods of 2019, respectively, primarily due to costs associated with certain compensation programs.
Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery, as well as LNG. Earnings from Technology decreased $73 million and increased $33 million in the three- and six-month periods of 2019, respectively, primarily due to changes in licensing revenues recognized between periods.
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, premiums incurred on the early retirement of debt, unrealized holding gains or losses on equity securities, and pension settlement expense. “Other” decreased by $195 million in the second quarter of 2019, compared with the same period of 2018, primarily due to an after-tax $312 million lower unrealized gain on our Cenovus Energy common shares, partly offset by lower pension settlement expense in the second quarter of 2018. In the six-month period of 2019, “Other” increased by $562 million primarily due to the absence of $195 million after-tax related to premiums on early retirement of debt and lower pension settlement expense in 2018, and an $154 million larger after-tax unrealized gain on our Cenovus Energy common shares in the six-month period of 2019, compared to the same period of 2018.
|
CAPITAL RESOURCES AND LIQUIDITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Indicators
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
June 30
|
|
|
December 31
|
|
|
|
|
2019
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
Short-term debt
|
$
|
114
|
|
|
112
|
|
Total debt
|
|
14,923
|
|
|
14,968
|
|
Total equity
|
|
33,074
|
|
|
32,064
|
|
Percent of total debt to capital*
|
|
31
|
%
|
|
32
|
|
Percent of floating-rate debt to total debt
|
|
5
|
%
|
|
5
|
|
*Capital includes total debt and total equity.
|
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs, and our ability to sell securities using our shelf registration statement. During the first six months of 2019, the primary uses of our available cash were $3,366 million to support our ongoing capital expenditures and investments program, $2,002 million to repurchase common stock, and $696 million to pay dividends. During the first six months of 2019, our cash, cash equivalents and restricted cash increased by $46 million to $6,197 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, dividend payments and required debt payments.
Significant Sources of Capital
Operating Activities
Cash provided by operating activities was $5,785 million for the first six months of 2019, compared with $5,741 million for the corresponding period of 2018.
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 NGLs. 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. Production levels are impacted by such factors as the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. As we undertake cash prioritization efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.
Investing Activities
Proceeds from asset sales for the first six months of 2019 were $701 million compared with $308 million for the corresponding period of 2018. In the first six months of 2019, we completed the sale of several assets
including our 30 percent interest in the Greater Sunrise Fields for $350 million, before customary adjustments. In the first six months of 2018, we completed the sale of several properties in the Lower 48 for net proceeds of $217 million. Other small transactions also closed in the first six months of 2018. See Note 5—Assets Held for Sale and Dispositions for additional information.
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments. The effective date of the transaction will be January 1, 2018. In the second quarter of 2019, we received deposits of $268 million related to this disposition which is included in the “Other” line of the “Cash Flows from Investing Activities” section of our consolidated cash flows. The transaction is subject to regulatory approval and other specific conditions precedent and is expected to be completed in the second half of 2019.
Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023. 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 program. 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.
The revolving credit facility supports the ConocoPhillips Company $6.0 billion commercial paper program, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days.
We had no commercial paper outstanding at June 30, 2019 or December 31, 2018. We had no direct outstanding borrowings or letters of credit under the revolving credit facility at June 30, 2019 or December 31, 2018. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at June 30, 2019.
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 June 30, 2019 and December 31, 2018, we had direct bank letters of credit of $223 million and $323 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. SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.
For information about guarantees, see Note 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures” section.
Our debt balance at June 30, 2019, was $15 billion, unchanged from December 31, 2018.
On January 30, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on March 1, 2019, to stockholders of record at the close of business on February 11, 2019. On May 1, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on June 3, 2019, to stockholders of record at the close of business on May 13, 2019. On July 11, 2019, we announced a quarterly dividend of $0.305 per share, payable September 3, 2019, to stockholders of record at the close of business on July 22, 2019.
In late 2016, we initiated our current share repurchase program. As of July 12, 2018, we had announced a total authorization to repurchase $15 billion of our common stock. We repurchased $3 billion in 2017 and $3 billion in 2018. We expect to execute $3.5 billion of the remaining $9 billion of our share repurchase program in 2019. Whether we undertake these additional repurchases is ultimately subject to numerous considerations, market conditions and other factors. See the “Our ability to declare and pay dividends and repurchase shares is subject to certain considerations” section in Risk Factors on pages 20-21 of our 2018 Annual Report on Form 10-K for additional information. Since our share repurchase program began in November 2016, we have repurchased 143 million shares at a cost of $8.1 billion through June 30, 2019.
|
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Six Months Ended
|
|
June 30
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
Alaska
|
$
|
780
|
|
844
|
|
Lower 48
|
|
1,770
|
|
1,640
|
|
Canada
|
|
232
|
|
218
|
|
Europe and North Africa
|
|
339
|
|
462
|
|
Asia Pacific and Middle East
|
|
219
|
|
293
|
|
Other International
|
|
1
|
|
3
|
|
Corporate and Other
|
|
25
|
|
74
|
|
Capital expenditures and investments
|
$
|
3,366
|
|
3,534
|
During the first six months of 2019, capital expenditures and investments supported key exploration and development programs, primarily:
Development, appraisal and exploration activities in the Lower 48, including Eagle Ford, Delaware in the Permian Basin, and Bakken.
Appraisal and development activities in Alaska related to the Western North Slope; development activities in the Greater Kuparuk Area and the Greater Prudhoe Area.
Development activities across assets in Norway and the U.K.
Optimization of oil sands development and appraisal activities in liquids-rich plays in Canada.
Continued development in China, Malaysia, Australia, and Indonesia.
Capital expenditures guidance has been increased from $6.1 billion to $6.3 billion. The capital increase allows for an additional drilling rig in Lower 48 and increased Alaska winter exploration activity. This guidance
excludes completed and announced acquisitions of approximately $0.3 billion. Total capital expenditures and investments for all activity is expected to be $6.6 billion.
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. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty 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.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 65–67 of our 2018 Annual Report on Form 10-K.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive
Environmental Response, Compensation and Liability Act (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 waste attributable to our past operations. As of June 30, 2019, there were 15 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.
At June 30, 2019, our balance sheet included a total environmental accrual of $175 million, compared with $178 million at December 31, 2018, for remediation activities in the United States 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
Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on 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 and precursors for possible regulation that do or could affect our operations include:
The EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggered 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.
Colorado’s HB-19 1261, approved May 30, 2019, introducing statewide goals to reduce 2025 GHG emissions by at least 26 percent, 2030 GHG emissions by at least 50 percent, and 2050 GHG emissions by at least 90 percent of the levels of GHG emissions that existed in 2005.
For other examples of legislation or precursors for possible regulation and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 67–69 of our 2018 Annual Report on Form 10-K.
In December 2018, we became a Founding Member of the Climate Leadership Council (CLC), an international policy institute founded in collaboration with business and environmental interests to develop a carbon dividend plan. Participation in the CLC provides another opportunity for ongoing dialogue about carbon pricing and framing the issues in alignment with our public policy principles. We also belong to and fund Americans For Carbon Dividends, the education and advocacy branch of the CLC.
In 2017 and 2018, cities, counties, and a state government in California, New York, Washington, Rhode Island and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits. The lawsuits brought by the Cities of San Francisco, Oakland and New York have been dismissed by the district courts and appeals are pending. Lawsuits filed by other cities and counties in California and Maryland are currently stayed pending appeals to the U.S. Court of Appeals for the Ninth Circuit and Fourth Circuit on the issue of whether they will proceed in federal or state court.
Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations in Louisiana. All parish lawsuits are stayed pending an appeal to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or state court. ConocoPhillips will vigorously defend against these lawsuits.
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:
Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels.
The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may result in recognition of impairment costs on our long-lived assets, leaseholds and nonconsolidated equity investments.
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.
Reductions in reserves replacement rates, whether as a result of the significant declines in commodity prices or otherwise.
Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
Unexpected changes in costs or technical requirements for constructing, modifying or operating E&P facilities.
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.
Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.
Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.
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.
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.
Changes in international monetary conditions and foreign currency exchange rate fluctuations.
Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as aluminum and steel) used in the operation of our business.
Substantial investment in and development use of, competing or alternative energy sources, including as a result of existing or future environmental rules and regulations.
Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
Liability resulting from litigation or our failure to comply with applicable laws and regulations.
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 NGLs pricing, regulation or taxation; the impact of and uncertainty surrounding the U.K.’s decision to withdraw from the EU; and other political, economic or diplomatic developments.
Volatility in the commodity futures markets.
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.
Competition and consolidation in the oil and gas E&P industry.
Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets.
Our inability to execute, or delays in the completion, of any asset dispositions or acquisitions we elect to pursue.
Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for asset dispositions or acquisitions, or that such approvals may require modification to the terms of the transactions or the operation of our remaining business.
Potential disruption of our operations as a result of asset dispositions or acquisitions, including the diversion of management time and attention.
Our inability to deploy the net proceeds from any asset dispositions we undertake in the manner and timeframe we currently anticipate, if at all.
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.
The operation and financing of our joint ventures.
The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.
Our inability to realize anticipated cost savings and expenditure reductions.
The factors generally described in Item 1A—Risk Factors in our 2018 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the six months ended June 30, 2019, does not differ materially from that discussed under Item 7A in our 2018 Annual Report on Form 10-K.
Item 4. 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 June 30, 2019, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President 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 and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of June 30, 2019.
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.
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
There are no new material legal proceedings or material developments with respect to matters previously disclosed in Item 3 of our 2018 Annual Report on Form 10-K.
Item 1A. RISK FACTORS
There have been no material changes from the risk factors disclosed in Item 1A of our 2018 Annual Report on Form 10-K.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Period
|
Total Number of Shares Purchased
|
*
|
Average Price Paid per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
|
Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 1-30, 2019
|
|
3,781,672
|
|
$
|
66.21
|
|
3,781,672
|
|
$
|
7,873
|
|
|
May 1-31, 2019
|
|
8,655,392
|
|
|
61.85
|
|
8,655,392
|
|
|
7,337
|
|
|
June 1-30, 2019
|
|
7,839,084
|
|
|
59.22
|
|
7,839,084
|
|
|
6,873
|
|
|
|
|
20,276,148
|
|
$
|
61.65
|
|
20,276,148
|
|
|
|
|
|
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
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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 repurchase an additional $3 billion of common stock through 2019. On July 12, 2018, we announced an authorization of an additional $9 billion for share repurchases at any time or from time to time (whether before, on or after December 31, 2019) bringing the total program authorization to $15 billion. As of June 30, 2019, approximately $6.9 billion remained available for purchase under the program. 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. See the “Our ability to declare and pay dividends and repurchase shares is subject to certain considerations” section in Risk Factors on pages 20–21 of our 2018 Annual Report on Form 10-K.
Item 6. EXHIBITS
* Filed herewith.
SIGNATURE
Pursuant to the requirements 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.
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CONOCOPHILLIPS
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/s/ Catherine A. Brooks
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Catherine A. Brooks
Vice President and Controller
(Chief Accounting and Duly Authorized Officer)
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August 1, 2019
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