10-Q 1 d577738d10q.htm 10-Q 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number: 001-32395

 

 

ConocoPhillips

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   01-0562944
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer      Smaller reporting company  
Emerging growth company       

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The registrant had 1,170,066,208 shares of common stock, $.01 par value, outstanding at March 31, 2018.

 

 

 


Table of Contents

CONOCOPHILLIPS

TABLE OF CONTENTS

 

     Page  

Part I—Financial Information

  

Item 1. Financial Statements

  

Consolidated Income Statement

     1  

Consolidated Statement of Comprehensive Income

     2  

Consolidated Balance Sheet

     3  

Consolidated Statement of Cash Flows

     4  

Notes to Consolidated Financial Statements

     5  

Supplementary Information—Condensed Consolidating Financial Information

     32  

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     36  

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     55  

Item 4. Controls and Procedures

     55  

Part II—Other Information

  

Item 1. Legal Proceedings

     56  

Item 1A. Risk Factors

     56  

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     57  

Item 6. Exhibits

     58  

Signature

     59  


Table of Contents

PART I. FINANCIAL INFORMATION

 

Item 1. FINANCIAL STATEMENTS

 

Consolidated Income Statement      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018       2017
  

 

 

 

Revenues and Other Income

    

Sales and other operating revenues

   $ 8,798       7,518  

Equity in earnings of affiliates

     208       200  

Gain on dispositions

     7       22  

Other income (loss)

     (52     31  

 

 

Total Revenues and Other Income

     8,961       7,771  

 

 

Costs and Expenses

    

Purchased commodities

     3,714       3,192  

Production and operating expenses

     1,171       1,291  

Selling, general and administrative expenses

     99       97  

Exploration expenses

     95       550  

Depreciation, depletion and amortization

     1,412       1,979  

Impairments

     12       175  

Taxes other than income taxes

     183       231  

Accretion on discounted liabilities

     88       95  

Interest and debt expense

     184       315  

Foreign currency transaction losses

     30       10  

Other expense

     197       68  

 

 

Total Costs and Expenses

     7,185       8,003  

 

 

Income (loss) before income taxes

     1,776       (232

Income tax provision (benefit)

     876       (831

 

 

Net income

     900       599  

Less: net income attributable to noncontrolling interests

     (12     (13

 

 

Net Income Attributable to ConocoPhillips

   $ 888       586  

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)

    

Basic

   $ 0.75       0.47  

Diluted

     0.75       0.47  

 

 

Dividends Paid Per Share of Common Stock (dollars)

   $ 0.29       0.27  

 

 

Average Common Shares Outstanding (in thousands)

    

Basic

     1,179,792       1,243,280  

Diluted

     1,186,454       1,248,722  

 

 

*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07.

See Note 2—Changes in Accounting Principles, for additional information.

See Notes to Consolidated Financial Statements.

 

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Consolidated Statement of Comprehensive Income      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018     2017  
  

 

 

 

Net Income

   $ 900       599  

Other comprehensive income

    

Defined benefit plans

    

Reclassification adjustment for amortization of prior service credit included in net income

     (10     (9

Net actuarial loss arising during the period

           (7

Reclassification adjustment for amortization of net actuarial losses included in net income

     24       90  

Income taxes on defined benefit plans

     (3     (26

 

 

Defined benefit plans, net of tax

     11       48  

 

 

Foreign currency translation adjustments

     78       184  

 

 

Foreign currency translation adjustments, net of tax

     78       184  

 

 

Other Comprehensive Income, Net of Tax

     89       232  

 

 

Comprehensive Income

     989       831  

Less: comprehensive income attributable to noncontrolling interests

     (12     (13

 

 

Comprehensive Income Attributable to ConocoPhillips

   $ 977       818  

 

 

See Notes to Consolidated Financial Statements.

 

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Consolidated Balance Sheet      ConocoPhillips  

 

                             
     Millions of Dollars  
     March 31
2018
    December 31
2017
 
  

 

 

 

Assets

    

Cash and cash equivalents

   $ 4,984       6,325  

Short-term investments

     288       1,873  

Accounts and notes receivable (net of allowance of $3 million in 2018 and $4 million in 2017)

     4,032       4,179  

Accounts and notes receivable—related parties

     160       141  

Investment in Cenovus Energy

     1,776       1,899  

Inventories

     1,053       1,060  

Prepaid expenses and other current assets

     894       1,035  

 

 

Total Current Assets

     13,187       16,512  

Investments and long-term receivables

     9,572       9,599  

Loans and advances—related parties

     399       461  

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $66,710 million in 2018 and $64,748 million in 2017)

     45,997       45,683  

Other assets

     1,572       1,107  

 

 

Total Assets

   $ 70,727       73,362  

 

 

Liabilities

    

Accounts payable

   $ 3,824       4,009  

Accounts payable—related parties

     62       21  

Short-term debt

     337       2,575  

Accrued income and other taxes

     1,341       1,038  

Employee benefit obligations

     408       725  

Other accruals

     1,137       1,029  

 

 

Total Current Liabilities

     7,109       9,397  

Long-term debt

     16,709       17,128  

Asset retirement obligations and accrued environmental costs

     7,789       7,631  

Deferred income taxes

     5,409       5,282  

Employee benefit obligations

     1,832       1,854  

Other liabilities and deferred credits

     1,161       1,269  

 

 

Total Liabilities

     40,009       42,561  

 

 

Equity

    

Common stock (2,500,000,000 shares authorized at $.01 par value)

    

Issued (2018—1,787,239,080 shares; 2017—1,785,419,175 shares)

    

Par value

     18       18  

Capital in excess of par

     46,642       46,622  

Treasury stock (at cost: 2018—617,172,872 shares; 2017—608,312,034 shares)

     (40,406     (39,906

Accumulated other comprehensive loss

     (5,371     (5,518

Retained earnings

     29,663       29,391  

 

 

Total Common Stockholders’ Equity

     30,546       30,607  

Noncontrolling interests

     172       194  

 

 

Total Equity

     30,718       30,801  

 

 

Total Liabilities and Equity

   $ 70,727       73,362  

 

 

See Notes to Consolidated Financial Statements.

 

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Consolidated Statement of Cash Flows      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018     2017  
  

 

 

 

Cash Flows From Operating Activities

    

Net Income

   $ 900       599  

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation, depletion and amortization

     1,412       1,979  

Impairments

     12       175  

Dry hole costs and leasehold impairments

     20       406  

Accretion on discounted liabilities

     88       95  

Deferred taxes

     65       (1,314

Undistributed equity earnings

     (34     (43

Gain on dispositions

     (7     (22

Other

     29       (47

Working capital adjustments

    

Decrease in accounts and notes receivable

     139       78  

Decrease (increase) in inventories

     12       (76

Decrease (increase) in prepaid expenses and other current assets

     (22     10  

Decrease in accounts payable

     (181     (129

Increase (decrease) in taxes and other accruals

     (34     79  

 

 

Net Cash Provided by Operating Activities

     2,399       1,790  

 

 

Cash Flows From Investing Activities

    

Capital expenditures and investments

     (1,535     (966

Working capital changes associated with investing activities

     28       (26

Proceeds from asset dispositions

     169       35  

Net sales (purchases) of short-term investments

     1,593       (203

Collection of advances/loans—related parties

     59       57  

Other

     (392     129  

 

 

Net Cash Used in Investing Activities

     (78     (974

 

 

Cash Flows From Financing Activities

    

Repayment of debt

     (2,888     (839

Issuance of company common stock

     (18     (46

Repurchase of company common stock

     (500     (112

Dividends paid

     (338     (331

Other

     (32     (16

 

 

Net Cash Used in Financing Activities

     (3,776     (1,344

 

 

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash

     125       27  

 

 

Net Change in Cash, Cash Equivalents and Restricted Cash

     (1,330     (501

Cash, cash equivalents and restricted cash at beginning of period

     6,536     3,610  

 

 

Cash, Cash Equivalents and Restricted Cash at End of Period

   $ 5,206       3,109  

 

 

*Restated to include $211 million of restricted cash at January 1, 2018.

Restricted cash totaling $222 million is included in the “Other assets” line of our Consolidated Balance Sheet as of March 31, 2018.

See Notes to Consolidated Financial Statements.

 

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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 2017 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers,” and its amendments issued by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts with Customers,” collectively Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers,” (ASC Topic 606) beginning January 1, 2018. ASC Topic 606 outlines a single comprehensive model for an entity to use in accounting for revenue arising from all contracts with customers except where revenues are in scope of another accounting standard. The ASU superseded the revenue recognition requirements in ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. ASC Topic 606 sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity is required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods and services. ASC Topic 606 also requires certain additional revenue-related disclosures. The adoption of ASC Topic 606 did not have a material impact on our consolidated financial statements. See Note 20—Sales and Other Operating Revenues for additional information related to this ASC.

We adopted the provisions of FASB ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Liabilities,” (ASU No. 2016-01) beginning January 1, 2018. The ASU, among other things, requires an entity to record the changes in fair value of equity investments, other than investments accounted for using the equity method, within net income. Under this ASU, an entity is no longer able to recognize unrealized holding gains and losses on available-for-sale securities in other comprehensive income and instead must recognize them in the income statement. See Note 7—Investment in Cenovus Energy and Note 16—Accumulated Other Comprehensive Loss for additional information relating to this ASU.

 

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The cumulative effect of the changes made to our consolidated balance sheet at January 1, 2018, for the adoption of ASC Topic 606 and ASU No. 2016-01 were as follows:

 

                                                           
     Millions of Dollars  
     December 31
2017
    ASC Topic 606
Adjustments
    ASU No. 2016-01
Adjustments
    January 1
2018
 
  

 

 

 

Liabilities

        

Other accruals

   $ 1,029       104             1,133  

Total current liabilities

     9,397       104             9,501  

Deferred income taxes

     5,282       (31           5,251  

Other liabilities and deferred credits

     1,269       147             1,416  

Total liabilities

     42,561       220             42,781  

 

 

Equity

        

Accumulated other comprehensive loss

   $ (5,518           58       (5,460 ) 

Retained earnings

     29,391       (220     (58     29,113  

Total common stockholders’ equity

     30,607       (220           30,387  

Total equity

     30,801       (220           30,581  

 

 

For discussion of adjustments for ASU No. 2016-01 and ASC Topic 606, see Note 7—Investment in Cenovus Energy and Note 20—Sales and Other Operating Revenues, respectively.

We adopted the provisions of FASB ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” beginning January 1, 2018. We retrospectively applied the presentation of service cost separate from the other components of net periodic costs. The interest cost, expected return on plan assets, amortization of prior service cost/credit, recognized net actuarial loss/gain, settlement expense, curtailment loss/gain, and special termination benefits have been reclassified from the “Production and operating expenses,” “Selling, general and administrative expenses,” and “Exploration expenses” lines to the “Other expense” line on our consolidated income statement. We elected to apply the practical expedient which allows us to reclassify amounts disclosed previously in the employee benefit plans footnote as the basis for applying retrospective presentation for prior comparative periods as it is impracticable to determine the disaggregation of the cost components for amounts capitalized and amortized in those periods. On a prospective basis, the other components of net periodic benefit costs will not be included in amounts capitalized in inventory or properties, plants, and equipment (PP&E).

The effect of the retrospective presentation change related to the net periodic benefit cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated income statement was as follows:

 

                                            
     Millions of Dollars  
     Three Months Ended
March 31, 2017
 
     Previously
Reported
     Effect of Change
Higher/(Lower)
    As
Revised
 
  

 

 

 

Production and operating expenses

   $ 1,298        (7     1,291  

Selling, general and administrative expenses

     157        (60     97  

Exploration expenses

     551        (1     550  

Other expense

            68       68  

 

 

We adopted the provisions of FASB ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments,” beginning January 1, 2018. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash flows. We have made an accounting policy election

 

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to classify distributions received from equity method investees using the nature of the distribution approach which classifies distributions received from investees as either cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior presented periods.

We adopted the provisions of FASB ASU No. 2016-18, “Restricted Cash,” beginning January 1, 2018. This ASU requires amounts deemed restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and presentation should permit a reconciliation when cash, cash equivalents and restricted cash are presented in more than one line item on the balance sheet. We have amounts deposited in statutory bank accounts in certain countries to satisfy asset retirement obligations (ARO). These amounts are deemed restricted cash and are included in the “Other assets” line of our consolidated balance sheet. This standard is required to be applied retrospectively to all periods presented, but the impact in those periods was not material.

Note 3—Variable Interest Entities (VIEs)

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

Australia Pacific LNG Pty Ltd (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as liquefied natural gas (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 March 31, 2018, 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 12—Guarantees, for additional information.

Marine Well Containment Company, LLC (MWCC)

MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on a call-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on the ten-member Executive Committee responsible for overseeing the affairs of MWCC. In 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our consolidated balance sheet. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.

 

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At March 31, 2018, the carrying value of our equity method investment in MWCC was $135 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  
     March 31
2018
     December 31
2017
 
  

 

 

 

Crude oil and natural gas

   $ 503        512  

Materials and supplies

     550        548  

 

 
   $ 1,053        1,060  

 

 

Inventories valued on the last-in, first-out (LIFO) basis totaled $334 million and $341 million at March 31, 2018 and December 31, 2017, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $13 million and $124 million at March 31, 2018 and December 31, 2017, respectively.

Note 5—Assets Held for Sale, Sold or Acquired

Assets Held for Sale

As of March 31, 2018, our interest in the Barnett met the criteria for assets held for sale and had a net carrying value of approximately $250 million after recording a before-tax impairment of $44 million in the first quarter of 2018 to reduce the carrying value to fair value. We reclassified $295 million of PP&E to “Prepaid expenses and other current assets” and $48 million of noncurrent liabilities, primarily ARO, to “Other accruals” on our consolidated balance sheet as a result of being held for sale. The before-tax loss associated with our interest in the Barnett, including the impairment noted above was $35 million and $10 million for the three months ended March 31, 2018 and March 31, 2017, respectively. Marketing efforts ceased in April 2018, and the assets were reclassified as held for use. The Barnett results of operations are reported in our Lower 48 segment.

In addition to the Barnett, certain other properties with a net carrying value of approximately $212 million in our Lower 48 segment met the criteria for assets held for sale as of December 31, 2017. A portion of these properties was sold in the first quarter of 2018, the details of which are discussed in the “Assets Sold” section below. The remaining held for sale properties had a net carrying value of approximately $104 million, which is reflected in the “Prepaid expenses and other current assets” line on our consolidated balance sheet as of March 31, 2018. In April 2018, these properties were sold for their carrying value.

Assets Sold

In the first quarter of 2018, we completed the sale of certain properties in the Lower 48 segment for net proceeds of $112 million. No gain or loss was recognized on the sale.

Acquisition

In the first quarter of 2018, we entered into an agreement with Anadarko Petroleum Corporation to acquire its nonoperated interest in the Western North Slope of Alaska, as well as its interest in the Alpine pipeline, for $400 million, before customary adjustments. In accordance with the agreement, we paid a deposit of $383 million which is reflected in the “Other assets” line of our consolidated balance sheet and the “Other” line in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. The transaction is subject to regulatory approval and will be included in our Alaska segment.

 

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Note 6—Investments, Loans and Long-Term Receivables

APLNG

APLNG’s $8.5 billion project finance facility consists 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 will continue to make bi-annual payments until March 2029. At March 31, 2018, a balance of $7.5 billion was outstanding on the facility. See Note 12—Guarantees, for additional information.

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

At March 31, 2018, the carrying value of our equity method investment in APLNG was $7,707 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

Subsequent to March 31, 2018, distributions from APLNG commenced with the receipt of an initial payment in April 2018.

FCCL

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. For additional information on the Canada disposition and our investment in Cenovus Energy, see Note 7—Investment in Cenovus Energy.

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 March 31, 2018, significant loans to affiliated companies included $522 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 approximated 16.9 percent of issued and outstanding Cenovus common stock at closing.

At closing, the fair value and cost basis of our investment in 208 million Cenovus Energy common shares was $1.96 billion based on a price of $9.41 per share on the New York Stock Exchange.

We adopted the provisions of ASU No. 2016-01, beginning January 1, 2018, using the cumulative-effect approach. Results for reporting periods beginning January 1, 2018, are presented under ASU No. 2016-01 with all changes in the fair value of our equity securities reflected within the “Other income (loss)” line of our consolidated income statement and within the “Other” line in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows. Prior period amounts are not adjusted under the cumulative-effect method of adopting ASU No. 2016-01. See Note 2—Changes in Accounting Principles and Note 16—Accumulated Other Comprehensive Loss for the effect on our consolidated balance sheet and the line items that have been impacted by the adoption of this standard.

 

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The cumulative effect of applying the standard was the reclassification of accumulated unrealized holding losses of $58 million, recognized in 2017, related to our investment in Cenovus Energy from accumulated other comprehensive loss to retained earnings.

Our investment on our consolidated balance sheet as of March 31, 2018, is carried at fair value of $1.78 billion, reflecting the closing price of Cenovus Energy shares on the New York Stock Exchange of $8.54 per share, a decrease of $123 million from $1.90 billion at year-end 2017. This decrease relates solely to the net unrealized loss recorded in the first quarter of 2018 relating to the shares held at the reporting date. See Note 15—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 March 31, 2018, was $861 million, an increase of $8 million from $853 million at year-end 2017. No suspended wells were charged to dry hole expense during the first three months of 2018 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2017.

Note 9—Impairments

During the three-month periods ended March 31, 2018 and 2017, we recognized before-tax impairment charges within the following segments:

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018      2017  
  

 

 

 

Alaska

   $        174  

Lower 48

     11         

Europe and North Africa

     1        1  

 

 
   $ 12        175  

 

 

The first quarter of 2018 included impairments in our Lower 48 segment of $11 million related to developed properties in our Barnett asset which were written down to fair value less costs to sell, partly offset by a revision to reflect finalized proceeds. See Note 5—Assets Held for Sale, Sold or Acquired, for additional information on our dispositions.

The first quarter of 2017 included an impairment in our Alaska segment of $174 million for the associated PP&E carrying value of our small interest in the Point Thomson Unit.

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

In the first quarter of 2017, we recorded a before-tax impairment of $51 million in our Lower 48 segment for the associated carrying value of capitalized undeveloped leasehold costs of Shenandoah in deepwater Gulf of Mexico following the suspension of appraisal activity by the operator.

 

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Note 10—Debt

As of March 31, 2018, our revolving credit facility, expiring in June 2019, was $6.75 billion. The revolving credit facility supports two commercial paper programs: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At March 31, 2018 and December 31, 2017, we had no direct outstanding borrowings under the revolving credit facility and no letters of credit. We had no commercial paper outstanding at March 31, 2018 or December 31, 2017, under both the ConocoPhillips and the ConocoPhillips Qatar Funding Ltd. commercial paper programs. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at March 31, 2018.

In the first quarter of 2018, we redeemed or repurchased a total $2,650 million of debt as described below:

 

   

4.20% Notes due 2021 with remaining principal of $1.0 billion.

   

2.875% Notes due 2021 with principal of $750 million.

   

2.2% Notes due 2020 with principal of $500 million.

   

8.125% Notes due 2030 with principal of $600 million (partial redemption of $210 million).

   

7.8% Notes due 2027 with principal of $300 million (partial redemption of $97 million).

   

7.9% Notes due 2047 with principal of $100 million (partial redemption of $40 million).

   

9.125% Notes due 2021 with principal of $150 million (partial redemption of $27 million).

   

8.20% Notes due 2025 with principal of $150 million (partial redemption of $16 million).

   

7.65% Notes due 2023 with principal of $88 million (partial redemption of $10 million).

We incurred premiums above book value to redeem or repurchase these debt instruments of $206 million.

At March 31, 2018, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. The VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

 

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Note 11—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2018 and 2017 was as follows:

 

                                                                                         
     Millions of Dollars  
     2018     2017  
     Common
Stockholders’
Equity
    Non-Controlling
Interest
    Total
Equity
    Common
Stockholders’
Equity
    Non-Controlling
Interest
    Total
Equity
 
  

 

 

   

 

 

 

Balance at January 1

   $ 30,607       194       30,801       34,974       252       35,226  

Net income

     888       12       900       586       13       599  

Dividends

     (338           (338 )      (331           (331

Repurchase of company common stock

     (500           (500     (112           (112

Distributions to noncontrolling interests

           (34     (34           (17     (17

Changes in Accounting Principles*

     (220           (220 )                   

Other changes, net**

     109             109       236             236  

 

 

Balance at March 31

   $ 30,546       172       30,718       35,353       248       35,601  

 

 

  *See Note 2—Changes in Accounting Principles for additional information related to ASC Topic 606.

**Includes components of other comprehensive income, which are disclosed separately in our Consolidated Statement of Comprehensive Income.

Note 12—Guarantees

At March 31, 2018, 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 March 31, 2018, 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 March 2018 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 11 years. Our maximum exposure under this guarantee is approximately $190 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At March 31, 2018, the carrying value of this guarantee was approximately $14 million.

 

   

In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of up to 24 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $940 million ($1.68 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.

 

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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 28 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $150 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $780 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of up to five 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 March 31, 2018, was approximately $100 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount at March 31, 2018, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

In 2012, we completed the separation of our downstream business, creating two independent energy companies: ConocoPhillips and Phillips 66. On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our downstream businesses formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.27 billion. At March 31, 2018, the carrying value of this guarantee is approximately $98 million and the remaining term is seven years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.

Note 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these

 

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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. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated.

At March 31, 2018, our balance sheet included a total environmental accrual of $173 million, compared with $180 million at December 31, 2017, 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.

 

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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 March 31, 2018, we had performance obligations secured by letters of credit of $367 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. In 2014, ConocoPhillips commenced a second arbitration under the rules of the International Chamber of Commerce (ICC) against PDVSA under the contracts that had established the Petrozuata and Hamaca projects (the Corocoro project is part of a separate ICC arbitration proceeding). In those proceedings, the ICC Tribunal ruled in April 2018 that PDVSA and two of its subsidiaries owed ConocoPhillips an indemnity of approximately $2.04 billion in connection with the expropriation of the projects and other pre-expropriation fiscal measures. Collection efforts are underway. In addition, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware, alleging that Venezuela and PDVSA have taken actions to improperly liquidate and expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, challenging a windfall profits tax and subsequent expropriation of Blocks 7 and 21. On April 24, 2012, Ecuador filed environmental and infrastructure counterclaims against Burlington relating to the alleged impacts to Blocks 7 and 21. Ecuador also filed the environmental and infrastructure counterclaims relating to Blocks 7 and 21 in a separate, parallel ICSID arbitration brought by Perenco Ecuador Limited, Burlington’s co-venturer and consortium operator. Perenco and Burlington each have joint liability for the counterclaims under their joint operating agreements. On December 14, 2012, the ICSID tribunal issued a decision in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. In February 2017, the ICSID tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and

 

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breach of the U.S.-Ecuador Bilateral Investment Treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for environmental and infrastructure impacts to Blocks 7 and 21. In December 2017, Burlington and Ecuador entered into a settlement agreement by which Ecuador agreed to pay Burlington $337 million in two installments. The first installment of $75 million was paid on December 1, 2017, and the second installment of $262 million was paid on April 13, 2018. The settlement includes an offset for the counterclaims decision, of which Burlington is entitled to a $24 million contribution from Perenco pursuant to the joint operating agreement. The ICSID arbitration between Perenco and Ecuador remains pending.

In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the Block 36 Production Sharing Contract relating to disputes arising thereunder. The arbitration is being conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person tribunal.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V. in connection with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. This arbitration is ongoing.

In 2017 and early 2018, cities and/or counties in California and New York have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits.

Note 14—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 natural gas liquids.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale (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  
     March 31
2018
     December 31
2017
 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 233        275  

Other assets

     49        36  

Liabilities

     

Other accruals

     238        282  

Other liabilities and deferred credits

     41        28  

 

 

 

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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
March 31
 
     2018     2017  
  

 

 

 

Sales and other operating revenues

   $ 43       51  

Other income (loss)

     4       1  

Purchased commodities

     (27     (38

 

 

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:

 

                             
     Open Position
Long/(Short)
 
     March 31
2018
    December 31
2017
 
  

 

 

 

Commodity

    

Natural gas and power (billions of cubic feet equivalent)

    

Fixed price

     (12     (29

Basis

     2       12  

 

 

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 and foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends and cash returns from net investments in foreign affiliates, 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  
     March 31
2018
     December 31
2017
 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 1        1  

Other assets

     7        6  

Liabilities

     

Other liabilities and deferred credits

     8        15  

 

 

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.

 

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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
March 31
 
     2018     2017  
  

 

 

 

Foreign currency transaction (gains) losses

   $ (5     7  

 

 

We had the following net notional position of outstanding foreign currency exchange derivatives:

 

                                            
     In Millions
Notional Currency
 
     March 31
2018
     December 31
2017
 
  

 

 

 

Foreign Currency Exchange Derivatives

        

Sell U.S. dollar, buy other currencies*

     USD        94         

Buy British pound, sell other currencies**

     GBP        33         

Sell British pound, buy other currencies***

     GBP               1  

Sell Canadian dollar, buy U.S. dollar

     CAD        1,186        1,225  

 

 

    *Primarily British pound and Norwegian krone.

  **Primarily Norwegian krone and euro.

***Primarily euro.

Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments that we currently invest include:

 

   

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.

These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these financial instruments are included in the “Short-term investments” line on our consolidated balance sheet.

 

                                                           
     Millions of Dollars  
     Carrying Amount  
     Cash and Cash Equivalents      Short-Term Investments  
     March 31
2018
     December 31
2017
     March 31
2018
     December 31
2017
 
  

 

 

 

Cash

   $ 869        948        

Time deposits

           

Remaining maturities from 1 to 90 days

     3,873        5,004        170        821  

Commercial paper

           

Remaining maturities from 1 to 90 days

     242        373        118        978  

Remaining maturities from 91 to 180 days

                          74  

 

 
   $ 4,984        6,325        288        1,873  

 

 

 

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Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government money market funds, government debt securities and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position on March 31, 2018 and December 31, 2017, was $61 million and $55 million, respectively. For these instruments, no collateral was posted as of March 31, 2018 or December 31, 2017. If our credit rating had been downgraded below investment grade on March 31, 2018, we would be required to post $61 million of additional collateral, either with cash or letters of credit.

Note 15—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

 

   

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

 

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corroborated market data is no longer available. Transfers occur at the end of the reporting period. At the end of the fourth quarter of 2017, our investment in Cenovus Energy transferred from Level 2 to Level 1 due to the lapsing of trading restrictions. There were no other material transfers between levels during 2018 or 2017.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. This also includes our investment in common shares of Cenovus Energy, which is valued using quotes for shares on the New York Stock Exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

 

                                                                                                                       
     Millions of Dollars  
     March 31, 2018      December 31, 2017  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
  

 

 

    

 

 

 

Assets

                       

Investment in Cenovus Energy

   $ 1,776                      1,776        1,899                      1,899  

Commodity derivatives

     142        110        30        282        175        106        30        311  

 

 

Total assets

   $ 1,918        110        30        2,058        2,074        106        30        2,210  

 

 

Liabilities

                       

Commodity derivatives

   $ 151        109        19        279        158        111        41        310  

 

 

Total liabilities

   $ 151        109        19        279        158        111        41        310  

 

 

 

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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  
     Gross
Amounts
Recognized
     Gross
Amounts
Offset
     Net
Amounts
Presented
     Cash
Collateral
     Gross Amounts
without
Right of Setoff
     Net
Amounts
 
  

 

 

 

March 31, 2018

                 

Assets

   $ 282        184        98               7        91  

Liabilities

     279        184        95        9        3        83  

 

 

December 31, 2017

                 

Assets

   $ 311        186        125               4        121  

Liabilities

     310        186        124        7        5        112  

 

 

At March 31, 2018 and December 31, 2017, 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 3
Inputs
     Before-Tax
Loss
 

March 31, 2018

        

Net PP&E (held for sale)

   $ 250        250        44  

 

 

During the first quarter of 2018, net PP&E held for sale was written down to fair value, less costs to sell. The fair value was estimated using information gathered during recent marketing efforts. For additional information, see Note 5—Assets Held for Sale, Sold or Acquired.

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 the balance sheet approximates fair value.

   

Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.

   

Investment in Cenovus Energy shares: See Note 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.

 

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Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.

   

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  
     March 31
2018
     December 31
2017
     March 31
2018
     December 31
2017
 
  

 

 

    

 

 

 

Financial assets

           

Investment in Cenovus Energy

   $ 1,776        1,899        1,776        1,899  

Commodity derivatives

     98        125        98        125  

Total loans and advances—related parties

     524        586        524        586  

Financial liabilities

           

Total debt, excluding capital leases

     16,260        18,929        18,908        22,435  

Commodity derivatives

     86        117        86        117  

 

 

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
    Net
Unrealized
Loss on
Securities
    Foreign
Currency
Translation
    Accumulated
Other
Comprehensive
Income (Loss)
 
  

 

 

 

December 31, 2017

   $ (400     (58     (5,060     (5,518

Cumulative effect of adopting ASU No. 2016-01*

           58             58  

Other comprehensive income

     11             78       89  

 

 

March 31, 2018

   $ (389           (4,982 )      (5,371 ) 

 

 

*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:

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018      2017  
  

 

 

 

Defined benefit plans

   $ 11        53  

 

 

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $3 million and $28 million for the three-month periods ended March 31, 2018 and 2017, respectively. See Note 18—Employee Benefit Plans, for additional information.

 

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Note 17—Cash Flow Information    

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018     2017  
  

 

 

 

Cash Payments

    

Interest

   $ 220       327  

Income taxes

     521       150  

 

 

Net Sales (Purchases) of Short-Term Investments

    

Short-term investments purchased

   $ (206     (243

Short-term investments sold

     1,799       40  

 

 
   $ 1,593       (203

 

 

Note 18—Employee Benefit Plans

Pension and Postretirement Plans

 

                                                                                         
     Millions of Dollars  
     Pension Benefits     Other Benefits  
     2018     2017     2018     2017  
     U.S.     Int’l.     U.S.     Int’l.              
  

 

 

   

 

 

   

 

 

   

 

 

     

Components of Net Periodic Benefit Cost

            

Three Months Ended March 31

            

Service cost

   $ 21       21       23       19              

Interest cost

     27       27       32       26       2       2  

Expected return on plan assets

     (34     (40 )      (34     (39            

Amortization of prior service cost (credit)

           (1 )      1       (1     (9 )      (9

Recognized net actuarial loss (gain)

     15       9       19       12             (1

Settlements

                 60                    

 

 

Net periodic benefit cost

   $ 29       16       101       17       (7 )      (8

 

 

The components of net periodic benefit cost, other than the service cost component, are included in the “Other expense” line item on our consolidated income statement.

During the first three months of 2018, we contributed $12 million to our domestic benefit plans and $63 million to our international benefit plans. In 2018, we expect to contribute approximately $70 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $150 million to our international qualified and nonqualified pension and postretirement benefit plans.

 

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Severance Accrual

The following table summarizes our severance accrual activity for the three-month period ended March 31, 2018:

 

              
     Millions of Dollars  

Balance at December 31, 2017

   $ 53  

Accruals

     8  

Benefit payments

     (22

Foreign currency translation adjustments

     1  

 

 

Balance at March 31, 2018

   $ 40  

 

 

Of the remaining balance at March 31, 2018, $18 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
March 31
 
     2018     2017  
  

 

 

 

Operating revenues and other income

   $ 23       29  

Purchases

     24       23  

Operating expenses and selling, general and administrative expenses

     15       12  

Net interest (income) expense*

     (3     (3

 

 

*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

Transitional Arrangements

We adopted the provisions of ASC Topic 606 beginning January 1, 2018, using the modified retrospective approach, which we have applied to contracts within the scope of the standard that had not been completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018, are presented under ASC Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC Topic 605. See Note 2—Changes in Accounting Principles for the effect on our consolidated balance sheet and the line items which have been impacted by the adoption of this standard.

The cumulative effect of applying the standard relates solely to certain licensing arrangements where revenue was previously recognized ($61 million in 2011, $146 million in 2015 and $44 million in 2017) based on contractual milestones. Under ASC Topic 606, such revenues are recognized when the customer has the ability to utilize and benefit from its right to use the license. As a result, such historically recognized revenues must be reversed through a cumulative effect adjustment and deferred until such time when the customer has the ability to utilize and benefit from the license. The cumulative effect adjustment relates to contracts that were not substantially completed at the date of implementation.

 

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Accounting Policy

Revenues associated with the sales of crude oil, bitumen, natural gas, LNG, natural gas liquids and other items are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. These products are typically sold at prevailing market prices. We allocate variable market-based consideration to deliveries (performance obligations) in the current period as that consideration relates specifically to our efforts to transfer control of current period deliveries to the customer and represents the amount we expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or less.

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.

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
March 31
 
     2018       2017

 

 

Revenue from contracts with customers

   $ 6,545       5,158  

Revenue from contracts outside the scope of ASC Topic 606

    

Physical contracts meeting the definition of a derivative

     2,261       2,425  

Financial derivative contracts

     (8     (65

 

 

Consolidated sales and other operating revenues

   $ 8,798       7,518  

 

 

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

 

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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
March 31
 
     2018        2017
  

 

 

 

Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment

     

Lower 48

   $ 1,713        1,727  

Canada

     191        279  

Europe and North Africa

     357        419  

 

 

Physical contracts meeting the definition of a derivative

   $ 2,261        2,425  

 

 

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.    

 

                             
     Millions of Dollars  
     Three Months Ended
March  31
 
     2018        2017
  

 

 

 

Revenue from Contracts Outside the Scope of ASC Topic 606 by Product

     

Crude oil

   $ 286        141  

Natural gas

     1,890        2,194  

Other

     85        90  

 

 

Physical contracts meeting the definition of a derivative

   $ 2,261        2,425  

 

 

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.    

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At March 31, 2018, the “Accounts and notes receivable” line on our consolidated balance sheet, includes trade receivables of $2,625 million compared with $2,675 million at December 31, 2017, 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.

 

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Table of Contents
              
     Millions of Dollars  

Contract Liabilities

  

At January 1, 2018

   $ 251  

 

 

At March 31, 2018

   $ 251  

 

 

Amounts Recognized in the Consolidated Balance Sheet at March 31, 2018

  

Current liabilities

   $ 153  

Non-current liabilities

     98  

 

 
   $ 251  

 

 

We expect to recognize such amounts between 2018 and 2019 as construction is completed.

Prior to the adoption of ASC Topic 606, contractual payments received would have been recognized as sales and other operating revenues in the current period.

Note 21—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, 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.

 

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Analysis of Results by Operating Segment

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018       2017
  

 

 

 

Sales and Other Operating Revenues

    

Alaska

   $ 1,385       1,007  

 

 

Lower 48

     3,952       3,230  

Intersegment eliminations

     (3     (3

 

 

Lower 48

     3,949       3,227  

 

 

Canada

     891       870  

Intersegment eliminations

     (255     (86

 

 

Canada

     636       784  

 

 

Europe and North Africa

     1,608       1,443  

Asia Pacific and Middle East

     1,216       1,022  

Corporate and Other

     4       35  

 

 

Consolidated sales and other operating revenues

   $ 8,798       7,518  

 

 

Sales and Other Operating Revenues by Geographic Location

    

United States

   $ 5,336       4,240  

Australia

     440       383  

Canada

     636       784  

China

     218       205  

Indonesia

     215       199  

Malaysia

     344       237  

Norway

     663       689  

United Kingdom

     669       622  

Other foreign countries

     277       159  

 

 

Worldwide consolidated

   $ 8,798       7,518  

 

 

Sales and Other Operating Revenues by Product

    

Crude oil

   $ 4,450       3,290  

Natural gas

     2,796       2,922  

Natural gas liquids

     231       288  

Other**

     1,321       1,018  

 

 

Consolidated sales and other operating revenues by product

   $ 8,798       7,518  

 

 

  *Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

**Includes LNG and bitumen.

 

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Table of Contents
                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018     2017  
  

 

 

 

Net Income Attributable to ConocoPhillips

    

Alaska

   $ 524       (11

Lower 48

     308       (362

Canada

     (65     948  

Europe and North Africa

     245       171  

Asia Pacific and Middle East

     461       236  

Other International

     (44     (48

Corporate and Other

     (541     (348

 

 

Consolidated net income attributable to ConocoPhillips

   $ 888       586  

 

 
     Millions of Dollars  
     March 31
2018
    December 31
2017
 
  

 

 

 

Total Assets

    

Alaska

   $ 12,610       12,108  

Lower 48

     14,584       14,632  

Canada

     6,074       6,214  

Europe and North Africa

     12,267       11,870  

Asia Pacific and Middle East

     16,753       16,985  

Other International

     97       97  

Corporate and Other

     8,342       11,456  

 

 

Consolidated total assets

   $ 70,727       73,362  

 

 

 

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Note 22—Income Taxes

Our effective tax rate for the first quarter of 2018 was 49 percent compared with 358 percent for the first quarter of 2017.

 

                                                           
     Millions of Dollars     Percent of Pre-Tax Income (Loss)  
     Three Months Ended
March 31
    Three Months Ended
March 31
 
     2018     2017     2018     2017  
  

 

 

   

 

 

 

Income (Loss) before income taxes

        

United States

   $ 786       (794     44.3 %      342.2  

Foreign

     990       562       55.7       (242.2

 

 
   $ 1,776       (232     100.0 %      100.0  

 

 

Federal statutory income tax

   $ 373       (81     21.0 %      35.0  

Non-U.S. effective tax rates

     446       266       25.1       (114.7

Canada disposition

           (996           429.3  

Recovery of outside basis

           (835           359.9  

Adjustment to tax reserves

     (2     822       (0.1 )      (354.3

Adjustment to valuation allowance

     57       24       3.2       (10.3

State income tax

     19       (13     1.1       5.6  

Enhanced oil recovery credit

     (20     (16     (1.1 )      6.9  

Other

     3       (2     0.1       0.8  

 

 
   $ 876       (831     49.3 %      358.2  

 

 

The effective tax rate represents a blend of federal, state and foreign taxes and includes the impact of certain nondeductible items and adjustments to our valuation allowance. The effective tax rate for the three months ended March 31, 2018 also reflects the reduced federal corporate income tax rate as a result of the enactment of the Tax Cuts and Jobs Act (the Tax Legislation) in December 2017 and the impact of a change in the mix of our domestic and foreign earnings.

Our effective tax rate in the first quarter of 2017 was impacted by a tax benefit of $996 million related to our 2017 disposition of various assets in Canada. This tax benefit was primarily associated with a deferred tax recovery related to the Canadian capital gains exclusion component of the 2017 Canada disposition and the recognition of previously unrealizable Canadian capital asset tax basis. The Canada disposition, along with the associated restructuring of our Canadian operations, may generate an additional tax benefit of $822 million. However, since we believe it is not likely we will receive a corresponding cash tax savings, this $822 million benefit has been offset by a full tax reserve.

We have not revised any of our 2017 provisional estimates under Staff Accounting Bulletin 118 and ASU No. 2018-05, but we are continuing to gather information and are waiting for further guidance from the Internal Revenue Service, Securities Exchange Commission and FASB on the Tax Legislation.

The Tax Legislation subjects a U.S. shareholder to tax on Global Intangible Low-Taxed Income (GILTI) earned by certain foreign subsidiaries. The FASB Staff Q&A, Topic 740, No. 5, “Accounting for Global Intangible Low-Taxed Income,” states that an entity can make an accounting policy election to either recognize deferred taxes for temporary basis differences expected to reverse as GILTI in future years or provide for the tax expense related to GILTI in the year the tax is incurred as a period expense only. Given the complexity of the GILTI provisions, we are still evaluating the effects of the GILTI provisions and have not yet determined our accounting policy. At March 31, 2018, the current year U.S. income tax impact related to GILTI activities is immaterial.

 

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Note 23—New Accounting Standards

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. In January 2018, ASU No. 2016-02 was amended by the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” We plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, and continue to evaluate the ASU to determine the impact of adoption on our consolidated financial statements and disclosures, accounting policies and systems, business processes, and internal controls. We are currently implementing a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting requirements of the ASU. We also continue to monitor proposals issued by the FASB to clarify the ASU and certain industry implementation issues. While our evaluation of ASU No. 2016-02 and related implementation activities are ongoing, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASU No. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this ASU.

 

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Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, 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 ConocoPhillips Canada Funding Company I (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 March 2018, ConocoPhillips Company received a $1.2 billion loan repayment from a nonguarantor subsidiary to settle certain accumulated intercompany balances. This transaction had no impact on our consolidated financial statements.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

 

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Table of Contents
                                                                                         
     Millions of Dollars  
     Three Months Ended March 31, 2018  
Income Statement    ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Canada
Funding
Company I
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 

Revenues and Other Income

            

Sales and other operating revenues

   $       3,764             5,034             8,798  

Equity in earnings of affiliates

     954       1,499             251       (2,496     208  

Gain on dispositions

           3             4             7  

Other income (loss)

           (103           51             (52

Intercompany revenues

     9       56       44       1,204       (1,313      

 

 

Total Revenues and Other Income

     963       5,219       44       6,544       (3,809     8,961  

 

 

Costs and Expenses

            

Purchased commodities

           3,410             1,433       (1,129     3,714  

Production and operating expenses

           172             1,032       (33     1,171  

Selling, general and administrative expenses

     4       74             26       (5     99  

Exploration expenses

           53             42             95  

Depreciation, depletion and amortization

           132             1,280             1,412  

Impairments

           (9           21             12  

Taxes other than income taxes

           50             133             183  

Accretion on discounted liabilities

           4             84             88  

Interest and debt expense

     71       159       37       63       (146     184  

Foreign currency transaction (gains) losses

     18       (9     (27     48             30  

Other expense

           194             3             197  

 

 

Total Costs and Expenses

     93       4,230       10       4,165       (1,313     7,185  

 

 

Income before income taxes

     870       989       34       2,379       (2,496     1,776  

Income tax provision (benefit)

     (18     35       (9     868             876  

 

 

Net income

     888       954       43       1,511       (2,496     900  

Less: net income attributable to noncontrolling interests

                       (12           (12

 

 

Net Income Attributable to ConocoPhillips

   $ 888       954       43       1,499       (2,496     888  

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ 977       1,043       (25     1,582       (2,600     977  

 

 
Income Statement    Three Months Ended March 31, 2017*  

Revenues and Other Income

            

Sales and other operating revenues

   $       3,115             4,403             7,518  

Equity in earnings of affiliates

     657       1,173             160       (1,790     200  

Gain on dispositions

           13             9             22  

Other income

           2             29             31  

Intercompany revenues

     17       71       42       794       (924      

 

 

Total Revenues and Other Income

     674       4,374       42       5,395       (2,714     7,771  

 

 

Costs and Expenses

            

Purchased commodities

           2,765             1,190       (763     3,192  

Production and operating expenses

           132             1,160       (1     1,291  

Selling, general and administrative expenses

     4       76             22       (5     97  

Exploration expenses

           371             179             550  

Depreciation, depletion and amortization

           251             1,728             1,979  

Impairments

                       175             175  

Taxes other than income taxes

           49             182             231  

Accretion on discounted liabilities

           10             85             95  

Interest and debt expense

     129       165       37       139       (155     315  

Foreign currency transaction (gains) losses

     (7           49       (32           10  

Other expense

           70             (2           68  

 

 

Total Costs and Expenses

     126       3,889       86       4,826       (924     8,003  

 

 

Income (Loss) before income taxes

     548       485       (44     569       (1,790     (232

Income tax benefit

     (38     (172     (5     (616           (831

 

 

Net income (loss)

     586       657       (39     1,185       (1,790     599  

Less: net income attributable to noncontrolling interests

                       (13           (13

 

 

Net Income (Loss) Attributable to ConocoPhillips

   $ 586       657       (39     1,172       (1,790     586  

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ 818       889       (13     1,362       (2,238     818  

 

 

*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07.

See Note 2—Changes in Accounting Principles, for additional information.

See Notes to Consolidated Financial Statements.

 

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Table of Contents
                                                                                         
     Millions of Dollars  
     March 31, 2018  
Balance Sheet    ConocoPhillips     ConocoPhillips
Company
     ConocoPhillips
Canada
Funding
Company I
    All Other
Subsidiaries
     Consolidating
Adjustments
    Total
Consolidated
 

Assets

              

Cash and cash equivalents

   $       68        3       4,913              4,984  

Short-term investments

                        288              288  

Accounts and notes receivable

     6       1,974        36       4,817        (2,641     4,192  

Investment in Cenovus Energy

           1,776                           1,776  

Inventories

           139              914              1,053  

Prepaid expenses and other current assets

     1       161        7       752        (27     894  

 

 

Total Current Assets

     7       4,118        46       11,684        (2,668     13,187  

Investments, loans and long-term receivables*

     30,214       48,760        2,504       17,222        (88,729     9,971  

Net properties, plants and equipment

           4,280              42,192        (475     45,997  

Other assets

     19       1,036        188       1,729        (1,400     1,572  

 

 

Total Assets

   $ 30,240       58,194        2,738       72,827        (93,272     70,727  

 

 

Liabilities and Stockholders’ Equity

              

Accounts payable

   $       2,754        2       3,771        (2,641     3,886  

Short-term debt

     (5     263        7       82        (10     337  

Accrued income and other taxes

           163              1,178              1,341  

Employee benefit obligations

           310              98              408  

Other accruals

     57       420        52       634        (26     1,137  

 

 

Total Current Liabilities

     52       3,910        61       5,763        (2,677     7,109  

Long-term debt

     3,788       8,956        1,701       2,742        (478     16,709  

Asset retirement obligations and accrued environmental costs

           435              7,354              7,789  

Deferred income taxes

                        6,281        (872     5,409  

Employee benefit obligations

           1,318              514              1,832  

Other liabilities and deferred credits*

     2,416       7,467        922       7,407        (17,051     1,161  

 

 

Total Liabilities

     6,256       22,086        2,684       30,061        (21,078     40,009  

Retained earnings

     23,139       13,990        (638     13,460        (20,288     29,663  

Other common stockholders’ equity

     845       22,118        692       29,134        (51,906     883  

Noncontrolling interests

                        172              172  

 

 

Total Liabilities and Stockholders’ Equity

   $ 30,240       58,194        2,738       72,827        (93,272     70,727  

 

 

*Includes intercompany loans.

              
Balance Sheet    December 31, 2017  

Assets

              

Cash and cash equivalents

   $       234        4       6,087              6,325  

Short-term investments

                        1,873              1,873  

Accounts and notes receivable

     24       2,255        35       4,870        (2,864     4,320  

Investment in Cenovus Energy

           1,899                           1,899  

Inventories

           163              897              1,060  

Prepaid expenses and other current assets

     1       278        6       779        (29     1,035  

 

 

Total Current Assets

     25       4,829        45       14,506        (2,893     16,512  

Investments, loans and long-term receivables*

     29,400       47,974        2,533       15,050        (84,897     10,060  

Net properties, plants and equipment

           4,230              41,930        (477     45,683  

Other assets

     15       1,146        186       1,302        (1,542     1,107  

 

 

Total Assets

   $ 29,440       58,179        2,764       72,788        (89,809     73,362  

 

 

Liabilities and Stockholders’ Equity

              

Accounts payable

   $       3,094        1       3,799        (2,864     4,030  

Short-term debt

     (5     2,505        7       77        (9     2,575  

Accrued income and other taxes

           107              931              1,038  

Employee benefit obligations

           554              171              725  

Other accruals

     85       314        48       612        (30     1,029  

 

 

Total Current Liabilities

     80       6,574        56       5,590        (2,903     9,397  

Long-term debt

     3,787       9,321        1,703       2,794        (477     17,128  

Asset retirement obligations and accrued environmental costs

           432              7,199              7,631  

Deferred income taxes

                        6,263        (981     5,282  

Employee benefit obligations

           1,335              519              1,854  

Other liabilities and deferred credits*

     1,528       5,229        926       9,215        (15,629     1,269  

 

 

Total Liabilities

     5,395       22,891        2,685       31,580        (19,990     42,561  

Retained earnings

     22,867       13,317        (681     11,958        (18,070     29,391  

Other common stockholders’ equity

     1,178       21,971        760       29,056        (51,749     1,216  

Noncontrolling interests

                        194              194  

 

 

Total Liabilities and Stockholders’ Equity

   $ 29,440       58,179        2,764       72,788        (89,809     73,362  

 

 

*Includes intercompany loans.    

 

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Table of Contents
                                                                                         
    Millions of Dollars  
    Three Months Ended March 31, 2018  
Statement of Cash Flows   ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Canada
Funding
Company I
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 

Cash Flows From Operating Activities

           

Net Cash Provided by (Used in) Operating Activities

  $ (69     (123     (30     2,584       37       2,399  

 

 

Cash Flows From Investing Activities

           

Capital expenditures and investments

          (233           (1,308     6       (1,535

Working capital changes associated with investing activities

          (93           121             28  

Proceeds from asset dispositions

          141             39       (11     169  

Purchases of short-term investments

                      1,593             1,593  

Long-term advances/loans—related parties

          (4           (29     33        

Collection of advances/loans—related parties

          1,306             59       (1,306     59  

Intercompany cash management

    887       1,638             (2,525            

Other

                      (392           (392

 

 

Net Cash Provided by (Used in) Investing Activities

    887       2,755             (2,442     (1,278     (78

 

 

Cash Flows From Financing Activities

           

Issuance of debt

                29       4       (33      

Repayment of debt

          (2,807           (1,387     1,306       (2,888

Issuance of company common stock

    19                         (37     (18

Repurchase of company common stock

    (500                             (500

Dividends paid

    (338                             (338

Other

    1                   (38     5       (32

 

 

Net Cash Provided by (Used in) Financing Activities

    (818     (2,807     29       (1,421     1,241       (3,776

 

 

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash

          9             116             125  

 

 

Net Change in Cash, Cash Equivalents and Restricted Cash

          (166     (1     (1,163           (1,330

Cash, cash equivalents and restricted cash at beginning of period*

          234       4       6,298             6,536  

 

 

Cash, Cash Equivalents and Restricted Cash at End of Period

  $       68       3       5,135             5,206  

 

 
Statement of Cash Flows   Three Months Ended March 31, 2017  

Cash Flows From Operating Activities

           

Net Cash Provided by (Used in) Operating Activities

  $ (97     1,014       45       1,581       (753     1,790  

 

 

Cash Flows From Investing Activities

           

Capital expenditures and investments

          (149           (819     2       (966

Working capital changes associated with investing activities

          55             (81           (26

Proceeds from asset dispositions

          46             18       (29     35  

Purchases of short-term investments

                      (203           (203

Long-term advances/loans—related parties

          (30                 30        

Collection of advances/loans—related parties

          63             2,138       (2,144     57  

Intercompany cash management

    1,341       1,037             (2,378            

Other

                      129             129  

 

 

Net Cash Provided by (Used in) Investing Activities

    1,341       1,022             (1,196     (2,141     (974

 

 

Cash Flows From Financing Activities

           

Issuance of debt

                      30       (30      

Repayment of debt

    (805     (2,081           (97     2,144       (839

Issuance of company common stock

    3                         (49     (46

Repurchase of company common stock

    (112                             (112

Dividends paid

    (331                 (802     802       (331

Other

    1                   (44     27       (16

 

 

Net Cash Used in Financing Activities

    (1,244     (2,081           (913     2,894       (1,344

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

                      27             27  

 

 

Net Change in Cash and Cash Equivalents

          (45     45       (501           (501

Cash and cash equivalents at beginning of period

          358       13       3,239             3,610  

 

 

Cash and Cash Equivalents at End of Period

  $       313       58       2,738             3,109  

 

 

*Restated to include $211 million of restricted cash at January 1, 2018

Restricted cash totaling $222 million is included in the “Other assets” line of our Consolidated Balance Sheet as of March 31, 2018.

 

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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 54.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Our diverse portfolio primarily includes resource-rich North American unconventional assets and oil sands assets in Canada; lower-risk conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas, we had operations and activities in 17 countries, approximately 11,200 employees worldwide and total assets of $71 billion as of March 31, 2018.

Overview

The global oil market is rebalancing. Crude oil prices continued to improve in the first quarter of 2018; however, we believe prices are likely to remain cyclical in the future. Our value proposition principles, namely to maintain financial strength, grow our dividend and pursue disciplined growth, remain essentially unchanged and we are executing in accordance with our priorities for allocating future cash flows. In order, these priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares to provide value to our shareholders; and strategically 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 first quarter of 2018, we continued to make notable progress on our stated priorities. We increased our quarterly dividend by 7.5 percent to $0.285 per share; reduced our debt by $2.65 billion; repurchased 8.9 million shares of our common stock; and entered into an agreement with Anadarko Petroleum Corporation to acquire its nonoperated interest in the Western North Slope of Alaska, as well as its interest in the Alpine pipeline, for $400 million, before customary adjustments.                

Operationally, we remain focused on safely executing our capital program and remaining attentive to our costs. Production excluding Libya was 1,224 thousand barrels of oil equivalent per day (MBOED) in the first quarter of 2018, a decrease of 360 MBOED compared with the same period of 2017. Our underlying production, which excludes Libya and the first-quarter impact of dispositions of 402 MBOED in 2017, increased 42 MBOED or 4 percent compared with the same period of 2017. Underlying production on a per

 

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debt-adjusted share basis grew by 26 percent compared with the first quarter of 2017. 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.

Business Environment

Global oil market fundamentals continued to trend toward a firmer balance in the first quarter of 2018. Crude oil prices improved in the period as a result of slower growth in global oil production, strong global oil demand and lower global inventory levels.

The energy industry has periodically experienced 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 Organization of Petroleum Exporting Countries (OPEC), environmental laws, tax regulations, governmental policies and weather-related disruptions. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.

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 West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and Henry Hub natural gas:

 

LOGO

Brent crude oil prices averaged $66.76 per barrel in the first quarter of 2018, an increase of 24 percent compared with $53.78 per barrel in the first quarter of 2017, and an increase of 9 percent compared with $61.39 per barrel in the fourth quarter of 2017. Industry crude prices for WTI averaged $62.88 per barrel in the first quarter of 2018, an increase of 21 percent compared with $51.83 per barrel in the first quarter of 2017, and an increase of 14 percent compared with $55.35 per barrel in the fourth quarter of 2017.

 

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Henry Hub natural gas prices averaged $3.01 per MMBTU in the first quarter of 2018, a decrease of 9 percent compared with $3.32 per MMBTU in the first quarter of 2017, and an increase of 3 percent compared with $2.93 per MMBTU in the fourth quarter of 2017. Prices decreased relative to the same period of 2017 due to higher associated gas production in the contiguous United States, but increased from the prior quarter as a result of weather-driven demand growth.

Our realized bitumen price decreased from $21.56 per barrel in the first quarter of 2017 and $25.20 per barrel in the fourth quarter of 2017, to $14.06 per barrel in the first quarter of 2018. The change, compared to both periods, was primarily due to a deterioration in the WCS differential resulting from high inventory levels stemming from the Keystone outage coupled with constrained pipeline and rail export capacity.

Our total average realized price was $50.49 per barrel of oil equivalent (BOE) in the first quarter of 2018, an increase of 40 percent compared with $36.18 per BOE in the first quarter of 2017 and a 10 percent increase compared to the fourth quarter of 2017, reflecting higher average realized oil and natural gas prices. Realized natural gas prices improved relative to the first quarter of 2017 primarily due to higher realized international gas prices.

Key Operating and Financial Summary

Significant items during the first quarter of 2018 included the following:

 

   

Achieved first-quarter production excluding Libya of 1,224 MBOED; year-over-year underlying production excluding the impact of closed and planned dispositions grew 4 percent overall and 26 percent on a production per debt-adjusted share basis.

   

Grew year-over-year production in the Lower 48 Big 3—Eagle Ford, Bakken and Delaware—by 20 percent.

   

Increased quarterly dividend by 7.5 percent.

   

Paid down $2.7 billion of balance sheet debt. Ended the quarter with $17.0 billion of debt and $5.0 billion of cash and cash equivalents.

   

Increased planned share repurchases by 33 percent; repurchased $0.5 billion in the first quarter; on track for full-year share repurchases of $2 billion.

   

Cash provided by operating activities exceeded capital expenditures, dividends and share repurchases.

   

Acquired additional liquids-rich Montney acreage in Canada during the quarter and announced central Louisiana Austin Chalk entry.

   

Successfully completed six-well exploration and appraisal drilling program in Alaska.

Outlook

Production and Capital Guidance

Second-quarter 2018 production is expected to be 1,170 to 1,210 MBOED, reflecting seasonal turnarounds.

Full-year 2018 production guidance increased to 1,200 to 1,240 MBOED to reflect first-quarter outperformance and a change in disposition assumptions. These and other improvements more than offset the impact from a third-party gas pipeline in Malaysia that is now assumed to be out of service for the entire year. Production guidance excludes Libya.

Capital expenditures guidance of $5.5 billion remains unchanged. Our capital guidance excludes acquisition investment for the previously announced $0.4 billion bolt-on transaction in Alaska and the $0.1 billion acquisition of additional acreage in the Montney in Canada.

 

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2018, is based on a comparison with the corresponding period of 2017.

Consolidated Results

A summary of the company’s net income attributable to ConocoPhillips by business segment follows:

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2018     2017  
  

 

 

 

Alaska

   $ 524       (11

Lower 48

     308       (362

Canada

     (65     948  

Europe and North Africa

     245       171  

Asia Pacific and Middle East

     461       236  

Other International

     (44     (48

Corporate and Other

     (541     (348

 

 

Net income attributable to ConocoPhillips

   $ 888       586  

 

 

Net income attributable to ConocoPhillips increased 52 percent in the first quarter of 2018, mainly due to:

 

   

Higher realized crude oil and natural gas prices.

   

Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-production rates from reserve additions and disposition impacts.

   

Lower exploration expenses mainly due to reduced dry hole costs and leasehold impairment expense in our Lower 48 segment, as well as reduced other exploration expenses in our Other International segment.

   

A $109 million after-tax benefit resulting from an accrual reduction given a transportation cost ruling in Alaska by the Federal Energy Regulatory Commission (FERC).

   

Lower impairment expense.

   

Lower production and operating expenses, primarily due to asset disposition impacts.

   

Lower interest and debt expense.

The increases in net income were partly offset by:

 

   

The absence of deferred tax benefits totaling $996 million, primarily related to the disposition of certain Canadian assets, recognized in the first quarter of 2017.

   

After-tax charges totaling $193 million for premiums on debt retirements in the first quarter of 2018.

   

Lower volumes primarily due to asset dispositions in our Canada and Lower 48 segments.

   

A $123 million unrealized loss, recognized in the first quarter of 2018, on our Cenovus Energy common shares held at March 31, 2018.

See the “Segment Results” section for additional information.

 

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Income Statement Analysis    

Sales and other operating revenues increased 17 percent in the first quarter of 2018 mainly due to higher realized crude oil, LNG, natural gas and natural gas liquids prices, partly offset by lower sales volumes, primarily in our Canada and Lower 48 segments.

Purchased commodities increased 16 percent in the first quarter of 2018, mainly due to increased crude oil prices in the Lower 48. Additionally, purchased commodities increased due to higher diluent purchases in Canada.

Production and operating expenses decreased 9 percent in the first quarter of 2018 primarily due to asset disposition impacts.

Exploration expenses decreased 83 percent in the first quarter of 2018 due to lower dry hole costs, mainly driven by the absence of $291 million before-tax charges for multiple wells in Shenandoah in deepwater Gulf of Mexico in 2017; lower other exploration expenses mainly due to the absence of a $43 million before-tax charge in 2017 for the cancellation of our Athena drilling rig contract and other rig stacking costs in our Other International segment; and lower leasehold impairment expense mainly due to the absence of a $51 million before-tax charge for Shenandoah.

DD&A decreased 29 percent in the first quarter of 2018, mainly due to lower unit-of-production rates from reserve additions and disposition impacts in our Canada and Lower 48 segments.

Impairments decreased 93 percent in the first quarter of 2018. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Interest and debt expense decreased 42 percent in the first quarter of 2018 primarily due to lower interest on debt, given reduced debt levels, as well as lower interest from an accrual reduction given a transportation cost ruling by the FERC.

Other expense increased 190 percent in the first quarter of 2018 primarily due to before-tax charges of $206 million for premiums on early debt retirements.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax provision (benefit) and effective tax rate.

 

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Summary Operating Statistics

 

                             
     Three Months Ended
March 31
 
     2018      2017  
  

 

 

 

Average Net Production

     

Crude oil (MBD)(1)

     636        601  

Natural gas liquids (MBD)

     96        134  

Bitumen (MBD)

     66        223  

Natural gas (MMCFD)(2)

     2,828        3,809  

 

 

Total Production (MBOED)(3)

     1,269        1,593  

 

 
     Dollars Per Unit  

Average Sales Prices

     

Crude oil (per barrel)

   $ 65.49        50.97  

Natural gas liquids (per barrel)

     28.37        24.87  

Bitumen (per barrel)

     14.06        21.56  

Natural gas (per thousand cubic feet)

     5.13        3.84  

 

 
     Millions of Dollars  

Exploration Expenses

     

General administrative, geological and geophysical, and lease rental, and other

   $ 75        144 (4) 

Leasehold impairment

     5        63  

Dry holes

     15        343  

 

 
   $ 95        550  

 

 

(1) Thousands of barrels per day.

(2) Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

(3) Thousands of barrels of oil equivalent per day.

(4) Certain amounts have been reclassified to conform to the current period presentation as a result of the adoption of ASU No. 2017-07. See

Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2018, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production from operations decreased 20 percent in the first quarter of 2018 compared with the same period of 2017. The decrease primarily resulted from noncore asset dispositions, including our Canada and San Juan transactions, both completed in 2017; normal field decline; and higher unplanned downtime mainly in Malaysia. The decrease in production was partly offset by production from major developments, including tight oil plays in the Lower 48; Malikai in Malaysia; Surmont and Montney in Canada; as well as Australia Pacific LNG Pty Ltd (APLNG). The continued ramp-up of production in Libya and improved drilling and well performance in Alaska, China, Lower 48 and Norway also partly offset the decrease in production. Excluding Libya, our first-quarter production was 1,224 MBOED. Adjusted for the first-quarter impact of dispositions of 402 MBOED in 2017, our underlying production increased 42 MBOED, or 4 percent, compared with the first quarter of 2017.

 

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Segment Results

Alaska

 

                             
     Three Months Ended
March 31
 
     2018      2017  
  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)

   $ 524        (11

 

 

Average Net Production

     

Crude oil (MBD)

     174        175  

Natural gas liquids (MBD)

     16        15  

Natural gas (MMCFD)

     7        7  

 

 

Total Production (MBOED)

     191        191  

 

 

Average Sales Prices

     

Crude oil (dollars per barrel)

   $ 68.31        52.09  

Natural gas (dollars per thousand cubic feet)

     2.51        3.53  

 

 

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of March 31, 2018, Alaska contributed 24 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Alaska increased $535 million in the first quarter of 2018, compared with the same period of 2017. The increase in earnings was mainly due to higher realized crude oil prices. Additionally, earnings improved due to the absence of a $110 million