10-Q 1 d375594d10q.htm FORM 10-Q Form 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, 2017

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 1,237,103,953 shares of common stock, $.01 par value, outstanding at March 31, 2017.

 

 

 


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

     25  

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

     29  

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     49  

Item 4. Controls and Procedures

     49  

Part II—Other Information

  

Item 1. Legal Proceedings

     50  

Item 1A. Risk Factors

     50  

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

     51  

Item 6. Exhibits

     52  

Signature

     53  


Table of Contents

PART I. FINANCIAL INFORMATION

 

Item 1. FINANCIAL STATEMENTS

 

Consolidated Income Statement      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Revenues and Other Income

    

Sales and other operating revenues

   $ 7,518       5,121  

Equity in earnings (losses) of affiliates

     200       (149

Gain on dispositions

     22       23  

Other income

     31       20  

 

 

Total Revenues and Other Income

     7,771       5,015  

 

 

Costs and Expenses

    

Purchased commodities

     3,192       2,225  

Production and operating expenses

     1,298       1,354  

Selling, general and administrative expenses

     157       186  

Exploration expenses

     551       505  

Depreciation, depletion and amortization

     1,979       2,247  

Impairments

     175       136  

Taxes other than income taxes

     231       180  

Accretion on discounted liabilities

     95       109  

Interest and debt expense

     315       281  

Foreign currency transaction losses

     10       16  

 

 

Total Costs and Expenses

     8,003       7,239  

 

 

Loss before income taxes

     (232     (2,224

Income tax benefit

     (831     (768

 

 

Net income (loss)

     599       (1,456

Less: net income attributable to noncontrolling interests

     (13     (13

 

 

Net Income (Loss) Attributable to ConocoPhillips

   $ 586       (1,469

 

 

Net Income (Loss) Attributable to ConocoPhillips Per Share of

Common Stock (dollars)

    

Basic

   $ 0.47       (1.18

Diluted

     0.47       (1.18

 

 

Dividends Paid Per Share of Common Stock (dollars)

   $ 0.27       0.25  

 

 

Average Common Shares Outstanding (in thousands)

    

Basic

     1,243,280       1,244,557  

Diluted

     1,248,722       1,244,557  

 

 

See Notes to Consolidated Financial Statements.

 

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Table of Contents
Consolidated Statement of Comprehensive Income      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Net Income (Loss)

   $ 599       (1,456

Other comprehensive income (loss)

    

Defined benefit plans

    

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

     (9     (9

Net actuarial loss arising during the period

     (7     (231

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

     90       108  

Income taxes on defined benefit plans

     (26     50  

 

 

Defined benefit plans, net of tax

     48       (82

 

 

Foreign currency translation adjustments

     184       1,183  

 

 

Foreign currency translation adjustments, net of tax

     184       1,183  

 

 

Other Comprehensive Income, Net of Tax

     232       1,101  

 

 

Comprehensive Income (Loss)

     831       (355

Less: comprehensive income attributable to noncontrolling interests

     (13     (13

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ 818       (368

 

 

See Notes to Consolidated Financial Statements.

 

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Table of Contents
Consolidated Balance Sheet      ConocoPhillips  

 

                             
     Millions of Dollars  
     March 31     December 31  
     2017     2016  
  

 

 

 

Assets

    

Cash and cash equivalents

   $ 3,109       3,610  

Short-term investments

     252       50  

Accounts and notes receivable (net of allowance of $5 million in 2017 and $5 million in 2016)

     3,105       3,249  

Accounts and notes receivable—related parties

     254       165  

Inventories

     1,097       1,018  

Prepaid expenses and other current assets

     2,911       517  

 

 

Total Current Assets

     10,728       8,609  

Investments and long-term receivables

     21,153       21,091  

Loans and advances—related parties

     522       581  

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $66,400 million in 2017 and $73,075 million in 2016)

     54,440       58,331  

Other assets

     1,130       1,160  

 

 

Total Assets

   $ 87,973       89,772  

 

 

Liabilities

    

Accounts payable

   $ 3,494       3,631  

Accounts payable—related parties

     37       22  

Short-term debt

     1,095       1,089  

Accrued income and other taxes

     756       484  

Employee benefit obligations

     465       689  

Other accruals

     1,679       994  

 

 

Total Current Liabilities

     7,526       6,909  

Long-term debt

     25,340       26,186  

Asset retirement obligations and accrued environmental costs

     7,884       8,425  

Deferred income taxes

     7,568       8,949  

Employee benefit obligations

     2,534       2,552  

Other liabilities and deferred credits

     1,520       1,525  

 

 

Total Liabilities

     52,372       54,546  

 

 

Equity

    

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

    

Issued (2017—1,784,150,651 shares; 2016—1,782,079,107 shares)

    

Par value

     18       18  

Capital in excess of par

     46,510       46,507  

Treasury stock (at cost: 2017—547,046,698 shares; 2016—544,809,771 shares)

     (37,018     (36,906

Accumulated other comprehensive loss

     (5,961     (6,193

Retained earnings

     31,804       31,548  

 

 

Total Common Stockholders’ Equity

     35,353       34,974  

Noncontrolling interests

     248       252  

 

 

Total Equity

     35,601       35,226  

 

 

Total Liabilities and Equity

   $ 87,973       89,772  

 

 

See Notes to Consolidated Financial Statements.

 

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Table of Contents
Consolidated Statement of Cash Flows      ConocoPhillips  

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017       2016  
  

 

 

 

Cash Flows From Operating Activities

    

Net income (loss)

   $ 599       (1,456

Adjustments to reconcile net income (loss) to net cash provided by operating activities

    

Depreciation, depletion and amortization

     1,979       2,247  

Impairments

     175       136  

Dry hole costs and leasehold impairments

     406       360  

Accretion on discounted liabilities

     95       109  

Deferred taxes

     (1,314     (827

Distributions received greater than equity losses (undistributed equity earnings)

     (43     252  

Gain on dispositions

     (22     (23

Other

     (47     (126

Working capital adjustments

    

Decrease in accounts and notes receivable

     78       549  

Decrease (increase) in inventories

     (76     61  

Decrease in prepaid expenses and other current assets

     10       9  

Decrease in accounts payable

     (129     (454

Increase (decrease) in taxes and other accruals

     79       (416

 

 

Net Cash Provided by Operating Activities

     1,790       421  

 

 

Cash Flows From Investing Activities

    

Capital expenditures and investments

     (966     (1,821

Working capital changes associated with investing activities

     (26     (134

Proceeds from asset dispositions

     35       135  

Net purchases of short-term investments

     (203     (302

Collection of advances/loans—related parties

     57       53  

Other

     129       4  

 

 

Net Cash Used in Investing Activities

     (974     (2,065

 

 

Cash Flows From Financing Activities

    

Issuance of debt

           4,594  

Repayment of debt

     (839     (64

Issuance of company common stock

     (46     (42

Repurchase of company common stock

     (112      

Dividends paid

     (331     (313

Other

     (16     (38

 

 

Net Cash Provided by (Used in) Financing Activities

     (1,344     4,137  

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

     27       5  

 

 

Net Change in Cash and Cash Equivalents

     (501     2,498  

Cash and cash equivalents at beginning of period

     3,610       2,368  

 

 

Cash and Cash Equivalents at End of Period

   $ 3,109       4,866  

 

 

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 2016 Annual Report on Form 10-K.

Note 2—Variable Interest Entities (VIEs)

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

Australia Pacific LNG Pty Ltd (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as 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, 2017, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 5—Investments, Loans and Long-Term Receivables, and Note 10—Guarantees, for additional information.

Marine Well Containment Company, LLC (MWCC)

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

At March 31, 2017, the carrying value of our equity method investment in MWCC was $146 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.

 

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Note 3—Inventories

Inventories consisted of the following:

 

                             
     Millions of Dollars  
     March 31
2017
     December 31
2016
 
  

 

 

 

Crude oil and natural gas

   $ 509        418  

Materials and supplies

     588        600  

 

 
   $ 1,097        1,018  

 

 

Inventories valued on the last-in, first-out (LIFO) basis totaled $379 million and $269 million at March 31, 2017 and December 31, 2016, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $121 million and $104 million at March 31, 2017 and December 31, 2016, respectively.

Note 4—Assets Held for Sale and Other Planned Dispositions

Assets Held for Sale

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) oil sands partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment. The cash portion of the consideration is subject to customary adjustments. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars for every $1 Canadian dollar by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 Canadian dollars per barrel. On the date of signing, we received a $130 million deposit from Cenovus, which is included in the “Cash Flows From Investing Activities” section in our consolidated statement of cash flows. Both FCCL and the western Canada gas assets are included in the Canada segment. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to close in the second quarter of 2017.

At March 31, 2017, the carrying value of our equity investment in FCCL was $9.0 billion. Our interests in the western Canada producing properties were considered held for sale resulting in the reclassification of $2.4 billion of properties, plants and equipment (PP&E) to “Prepaid expenses and other current assets” and $671 million of noncurrent liabilities, primarily asset retirement obligations, to “Other accruals,” on our consolidated balance sheet. The before-tax loss associated with our interests in the western Canada gas producing properties was $61 million and $145 million for the three months ended March 31, 2017 and March 31, 2016, respectively. We reported before-tax equity earnings of $120 million and a before-tax equity loss of $154 million related to FCCL for the three months ended March 31, 2017 and March 31, 2016, respectively.

Other Planned Dispositions

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3.0 billion of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary adjustments. The six-year contingent payment is effective beginning January 1, 2018, and is due annually for the periods in which the monthly U.S. Henry Hub (HH) price is at or above $3.20 per million British thermal units (MMBTU). The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017. The San Juan Basin results of operations are reported within the Lower 48 segment.

 

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Table of Contents

At March 31, 2017, the net carrying value was approximately $5.8 billion, consisting primarily of $6.2 billion of PP&E and $392 million of asset retirement obligations. The assets met held for sale criteria in April 2017. A noncash impairment will be recorded in the second quarter of 2017.

Note 5—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, 2017, a balance of $8.2 billion was outstanding on the facility. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. See Note 10—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 2—Variable Interest Entities (VIEs), for additional information.

During the first quarter of 2017, the outlook for crude oil prices weakened, and as a result, the estimated fair value of our investment in APLNG declined to an amount below carrying value. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment was not other than temporary under the guidance of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 323, “Investments—Equity Method and Joint Ventures.” In reaching this conclusion, we primarily considered: (1) the volatility and uncertainty in commodity markets; (2) the intent and ability of ConocoPhillips to retain our investment in APLNG; and (3) the short length of time carrying value has been less than market value (fair value exceeded carrying value as of December 31, 2016). Fair value has been estimated based on an internal discounted cash flow model using estimated future production, an outlook of future prices from a combination of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign exchange rates provided by a third party, and a discount rate believed to be consistent with those used by principal market participants.

At March 31, 2017, the fair value of our investment in APLNG was estimated to be $8,629 million, resulting in an unrecognized impairment of $1,430 million. We will continue to monitor the relationship between the carrying value and the fair value of APLNG. Should we determine in the future there has been a loss in the value of our investment that is other than temporary, we would record a noncash impairment of our equity investment, calculated as the total difference between carrying value and fair value as of the end of the reporting period.

At March 31, 2017, the carrying value of our equity method investment in APLNG was $10,059 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

At March 31, 2017, the carrying value of our equity method investment in FCCL Partnership was $9,006 million, net of a $1,604 million reduction due to cumulative foreign currency translation effects. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet. On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second quarter of 2017. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information.

 

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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, 2017, significant loans to affiliated companies included $639 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

Note 6—Suspended Wells and Other Exploration Expenses

The capitalized cost of suspended wells at March 31, 2017, was $834 million, a decrease of $229 million from $1,063 million at year-end 2016. Two suspended wells in Shenandoah in the Gulf of Mexico totaling $94 million and one suspended well in Alaska totaling $17 million were charged to dry hole expense during the first three months of 2017 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2016.

In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we recorded a before-tax charge of $43 million net in the first quarter of 2017.

This charge is included in the “Exploration expenses” line on our consolidated income statement.

Note 7—Impairments

During the three-month periods ended March 31, 2017 and 2016, we recognized before-tax impairment charges within the following segments:

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

Alaska

   $ 174         

Lower 48

            9  

Europe and North Africa

     1        127  

 

 
   $ 175        136  

 

 

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 a nonoperated producing property.

The first quarter of 2016 included impairments in our Europe and North Africa segment of $127 million, primarily as a result of lower natural gas prices in the United Kingdom.

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 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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In the first quarter of 2016, due to lack of commerciality of a drilled well, we recorded a before-tax impairment of $95 million for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect in deepwater Gulf of Mexico. Additionally, following the completion of an initial marketing effort in the Gulf of Mexico, we recorded a before-tax impairment of $73 million, primarily due to changes in the estimated market value.

Note 8—Debt

As of March 31, 2017, our revolving credit facility, expiring in June 2019, was $6.75 billion. This 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, 2017 and December 31, 2016, 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, 2017 or December 31, 2016, 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, 2017.

In the first quarter of 2017, we made a prepayment of $805 million on our floating rate term loan due in 2019. As of March 31, 2017, the remaining balance on our term loan facility is $645 million. We have the right at any time and from time to time to prepay the term loan, in whole or in part, without premium or penalty upon notice to the Administrative Agent.

The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At March 31, 2017, we were in compliance with this covenant.

The term loan facility includes customary events of default (subject to specified cure periods, materiality qualifiers and exceptions), including the failure to pay any interest, principal or fees when due, the failure to perform or the violation of any covenant contained in the term loan facility, the making of materially inaccurate or false representations or warranties, a default on certain material indebtedness, insolvency or bankruptcy, a change of control and the occurrence of material Employee Retirement Income Security Act of 1974 (ERISA) events and certain judgments against us or our material subsidiaries.

At March 31, 2017, 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 9—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2017 and 2016 was as follows:

 

                                                                                         
     Millions of Dollars  
     2017     2016  
     Common
Stockholders’
Equity
   

Non-

Controlling
Interest

    Total
Equity
    Common
Stockholders’
Equity
   

Non-

Controlling
Interest

    Total
Equity
 
  

 

 

   

 

 

 

Balance at January 1

   $ 34,974       252       35,226       39,762       320       40,082  

Net income (loss)

     586       13       599       (1,469     13       (1,456

Dividends

     (331           (331     (313           (313

Repurchase of company common stock

     (112           (112                  

Distributions to noncontrolling interests

           (17     (17           (16     (16

Other changes, net*

     236             236       1,109       1       1,110  

 

 

Balance at March 31

   $ 35,353       248       35,601       39,089       318       39,407  

 

 

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

Note 10—Guarantees

At March 31, 2017, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At March 31, 2017, we had outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing March 2017 exchange rates:

 

   

We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is one year. Our maximum potential amount of future payments related to this guarantee is approximately $10 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

 

   

We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. In October 2016, we reached financial completion for Train 1, releasing a portion of our guarantee. Our remaining guarantee of the project financing will be released upon meeting certain two Train completion tests with milestones which we estimate should occur this year. Our maximum exposure at March 31, 2017, is $1.24 billion based upon our pro-rata share of the facility used at that date. At March 31, 2017, the carrying value of this guarantee was approximately $46 million.

 

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During the third quarter of 2016, we issued a guarantee for our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 12 years. Our maximum exposure under this guarantee is approximately $100 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At March 31, 2017, the carrying value of this guarantee was approximately $9 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 25 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $1 billion ($1.76 billion in the event of intentional or reckless breach), and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

 

   

We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 29 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 $540 million, which consist primarily of a guarantee of the residual value of a leased office building, guarantees of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of up to six years and would become payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties.

Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at March 31, 2017, was approximately $100 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount at March 31, 2017, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

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 $1.35 billion. At March 31, 2017, the carrying value of this guarantee is approximately $98 million and the remaining term is eight years. Because Phillips 66 has indemnified us for

 

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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 11—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated but 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 factors such 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.

 

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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, 2017, our balance sheet included a total environmental accrual of $260 million, compared with $247 million at December 31, 2016, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at March 31, 2017, we had performance obligations secured by letters of credit of $266 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. Separate arbitrations for contractual compensation against PDVSA are also pending before an International Chamber of Commerce (ICC) arbitration tribunal. In addition, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.

 

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In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims is complete. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and its co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set.

In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the Block 36 Production Sharing Contract relating to disputes arising thereunder. The arbitration will be conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person tribunal. The schedule for this arbitration has not yet been set.

Note 12—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 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
2017
     December 31
2016
 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 199        268  

Other assets

     52        44  

Liabilities

     

Other accruals

     196        300  

Other liabilities and deferred credits

     41        34  

 

 

 

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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
 
     2017     2016  
  

 

 

 

Sales and other operating revenues

   $ 51       (3

Other income

     1       1  

Purchased commodities

     (38     (1

 

 

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

 

                             
     Open Position
Long/(Short)
 
     March 31
2017
    December 31
2016
 
  

 

 

 

Commodity

    

Natural gas and power (billions of cubic feet equivalent)

    

Fixed price

     (30     (31

Basis

     31       2  

 

 

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

 

                             
     Millions of Dollars  
     March 31
2017
     December 31
2016
 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $        1  

Liabilities

     

Other accruals

     2        168  

 

 

 

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The 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
 
     2017      2016  
  

 

 

 

Foreign currency transaction losses

   $ 7        97  

 

 

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

 

                                            
     In Millions
Notional Currency
 
    
   March 31
2017
     December 31
2016
 
  

 

 

Sell U.S. dollar, buy other currencies*

   USD      212        13  

Buy U.S. dollar, sell other currencies**

   USD             25  

Buy British pound, sell other currencies***

   GBP      12        1,069  

Sell British pound, buy Norwegian krone

   GBP             51  

 

 

    *Primarily Canadian dollar and Norwegian krone.

  **Primarily British pound.

***Primarily Euro and Canadian dollar.

Financial Instruments

We have certain financial instruments on our consolidated balance sheet related to interest-bearing time deposits and commercial papers. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.

 

                                                           
     Millions of Dollars  
     Carrying Amount  
     Cash and Cash Equivalents      Short-Term Investments  
     March 31
2017
     December 31
2016
     March 31
2017
     December 31
2016
 
  

 

 

    

 

 

 

Cash

   $ 842        623                

Time deposits

           

Remaining maturities from 1 to 90 days

     2,267        2,987        190        39  

Remaining maturities from 91 to 180 days

                   62        11  

 

 
   $ 3,109        3,610        252        50  

 

 

Credit Risk

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

 

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

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

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

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on March 31, 2017 and December 31, 2016, was $35 million and $42 million, respectively. For these instruments, no collateral was posted as of March 31, 2017 or December 31, 2016. If our credit rating had been downgraded below investment grade on March 31, 2017, we would be required to post $35 million of additional collateral, either with cash or letters of credit.

Note 13—Fair Value Measurement

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

 

   

Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

   

Level 2: Inputs other than quoted prices that are directly or indirectly observable.

   

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1 during 2017 or 2016.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. 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

 

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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, 2017      December 31, 2016  
     Level 1        Level 2        Level 3        Total        Level 1        Level 2        Level 3        Total  
  

 

 

    

 

 

 

Assets

                       

Commodity derivatives

   $ 135        95        21        251        194        96        22        312  

 

 

Total assets

   $ 135        95        21        251        194        96        22        312  

 

 

Liabilities

                       

Commodity derivatives

   $ 152        70        15        237        207        105        22        334  

 

 

Total liabilities

   $ 152        70        15        237        207        105        22        334  

 

 

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, 2017

                 

Assets

   $ 251        157        94               4        90  

Liabilities

     237        157        80        16        5        59  

 

 

December 31, 2016

                 

Assets

   $ 312        221        91               5        86  

Liabilities

     334        221        113        12        12        89  

 

 

At March 31, 2017 and December 31, 2016, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

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.

 

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Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 5—Investments, Loans and Long-Term Receivables, for additional information.

   

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      December 31      March 31      December 31  
     2017      2016      2017      2016  
  

 

 

    

 

 

 

Financial assets

           

Commodity derivatives

   $ 94        91        94        91  

Total loans and advances—related parties

     641        701        641        701  

Financial liabilities

           

Total debt, excluding capital leases

     25,616        26,423        28,734        29,307  

Commodity derivatives

     64        101        64        101  

 

 

Note 14—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss in the equity section of our consolidated balance sheet included:

 

                                            
     Millions of Dollars  
     Defined
Benefit Plans
    Foreign
Currency
Translation
    Accumulated
Other
Comprehensive
Income (Loss)
 
  

 

 

 

December 31, 2016

   $ (547     (5,646     (6,193

Other comprehensive income

     48       184       232  

 

 

March 31, 2017

   $ (499     (5,462     (5,961

 

 

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
 
     2017      2016  
  

 

 

 

Defined benefit plans

   $ 53        63  

 

 

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $28 million and $36 million for the three-month periods ended March 31, 2017 and 2016, respectively. See Note 16—Employee Benefit Plans, for additional information.

 

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Note 15—Cash Flow Information    

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Cash Payments (Receipts)

    

Interest

   $ 327       244  

Income taxes

     150       133  

 

 

Net Sales (Purchases) of Short-Term Investments

    

Short-term investments purchased

   $ (243     (302

Short-term investments sold

     40        

 

 
   $ (203     (302

 

 

During the quarter, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap transactions which is included in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows.

We received a $130 million deposit from Cenovus Energy on the date of signing the definitive agreement to sell certain Canadian assets. This deposit is included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information on our Canada disposition.

Note 16—Employee Benefit Plans    

Pension and Postretirement Plans    

 

                                                                                         
     Millions of Dollars  
     Pension Benefits     Other Benefits  
Three Months Ended    March 31     March 31  
     2017     2016     2017     2016  
  

 

 

   

 

 

   

 

 

 
     U.S.     Int’l.     U.S.     Int’l.              
  

 

 

   

 

 

   

 

 

   

 

 

     

Components of Net Periodic Benefit Cost

            

Service cost

   $ 23       19       27       20             1  

Interest cost

     32       26       40       31       2       3  

Expected return on plan assets

     (34     (39     (43     (41            

Amortization of prior service cost (credit)

     1       (1     1       (1     (9     (9

Recognized net actuarial loss (gain)

     19       12       19       7       (1      

Settlements

     60             82                    

 

 

Net periodic benefit cost

   $ 101       17       126       16       (8     (5

 

 

During the first three months of 2017, we contributed $19 million to our domestic benefit plans and $41 million to our international benefit plans. In 2017, we expect to contribute approximately $340 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $120 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three-month period ended March 31, 2017, lump-sum benefit payments exceeded the sum of service and interest costs for the fiscal year for the U.S. qualified pension plan and certain U.S. nonqualified supplemental retirement plans. As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $60 million.

 

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Table of Contents

Severance Accrual

As a result of entering into a definitive agreement during the first quarter to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, a reduction in our overall employee workforce is expected in 2017. Severance accruals of $39 million were recorded during the three-month period ended March 31, 2017. The following table summarizes our severance accrual activity for the three-month period ended March 31, 2017:

 

              
     Millions of Dollars  

Balance at December 31, 2016

   $ 80  

Accruals

     39  

Benefit payments

     (45

Foreign currency translation adjustments

     (1

 

 

Balance at March 31, 2017

   $ 73  

 

 

Of the remaining balance at March 31, 2017, $48 million is classified as short-term.

Note 17—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
 
     2017     2016  
  

 

 

 

Operating revenues and other income

   $ 29       27  

Purchases

     23       24  

Operating expenses and selling, general and administrative expenses

     12       16  

Net interest (income) expense*

     (3     (3

 

 

*We paid interest to, or received interest from various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 18—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 (loss) attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

 

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Table of Contents

Analysis of Results by Operating Segment

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Sales and Other Operating Revenues

    

Alaska

   $ 1,007       778  

 

 

Lower 48

     3,230       2,145  

Intersegment eliminations

     (3     (7

 

 

Lower 48

     3,227       2,138  

 

 

Canada

     870       425  

Intersegment eliminations

     (86     (35

 

 

Canada

     784       390  

 

 

Europe and North Africa

     1,443       923  

Asia Pacific and Middle East

     1,022       837  

Corporate and Other

     35       55  

 

 

Consolidated sales and other operating revenues

   $ 7,518       5,121  

 

 

Net Income (Loss) Attributable to ConocoPhillips

    

Alaska

   $ (11     (2

Lower 48

     (362     (820

Canada

     948       (294

Europe and North Africa

     171       (51

Asia Pacific and Middle East

     236       (5

Other International

     (48     (24

Corporate and Other

     (348     (273

 

 

Consolidated net income (loss) attributable to ConocoPhillips

   $ 586       (1,469

 

 

 

                             
     Millions of Dollars  
     March 31
2017
     December 31
2016
 
  

 

 

 

Total Assets

     

Alaska

   $ 12,095        12,314  

Lower 48

     21,746        22,673  

Canada

     17,707        17,548  

Europe and North Africa

     11,562        11,727  

Asia Pacific and Middle East

     20,058        20,451  

Other International

     99        97  

Corporate and Other

     4,706        4,962  

 

 

Consolidated total assets

   $ 87,973        89,772  

 

 

Note 19—Income Taxes

Our effective tax rate for the first quarter of 2017 was 358 percent compared with 35 percent for the first quarter of 2016. The increase in the effective tax rate was primarily due to the recognition of deferred tax benefits associated with the disposition of certain Canadian assets, discussed below, and lower before-tax losses in low tax jurisdictions. This is partially offset by our higher before-tax income in high tax jurisdictions.

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership and the majority of our western Canada gas assets. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to

 

22


Table of Contents

close in the second quarter of 2017. During the first quarter, we recorded a $996 million financial accounting tax benefit primarily associated with a deferred tax recovery related to the Canadian capital gains exclusion component of the transaction and the recognition of previously unrealizable Canadian capital asset tax basis. The disposition, along with the associated restructuring of our Canadian operations, may generate an additional tax benefit of approximately $800 million. However, since we believe it is not likely we will receive a corresponding cash tax savings of this amount, the benefit has not been recorded. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information on our Canada disposition.

Note 20—New Accounting Standards

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers” (ASU No. 2014-09), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts.

In August 2015, the FASB issued ASU No. 2015-14, “Deferral of the Effective Date,” which defers the effective date of ASU No. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.

ASU No. 2014-09 was amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts With Customers.”

We will adopt the provisions of ASU No. 2014-09, as amended, with effect from January 1, 2018, and have elected not to early adopt the standard. We intend to adopt the new standard using the modified retrospective approach which we will apply only to contracts within the scope of the standard that are not complete at the date of initial application. Under this approach, we will apply the guidance retrospectively only to the most current period presented in the financial statements. We continue to assess the impact of adoption of the standard on our current accounting policies and revenue-related disclosures. The impact to our financial statements is expected to be immaterial.

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. While we continue to evaluate the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.

 

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Table of Contents

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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Table of Contents

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to 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.

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, 2017  
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

   $       3,115             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

           141             1,158       (1     1,298  

Selling, general and administrative expenses

     4       136             22       (5     157  

Exploration expenses

           372             179             551  

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  

 

 

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  

 

 
Income Statement    Three Months Ended March 31, 2016  

Revenues and Other Income

            

Sales and other operating revenues

   $       2,072             3,049             5,121  

Equity in losses of affiliates

     (1,427     (750           (444     2,472       (149

Gain on dispositions

           22             1             23  

Other income (loss)

           (6           26             20  

Intercompany revenues

     18       81       56       525       (680      

 

 

Total Revenues and Other Income

     (1,409     1,419       56       3,157       1,792       5,015  

 

 

Costs and Expenses

            

Purchased commodities

           1,848             879       (502     2,225  

Production and operating expenses

           253             1,104       (3     1,354  

Selling, general and administrative expenses

     3       154             35       (6     186  

Exploration expenses

           431             74             505  

Depreciation, depletion and amortization

           257             1,990             2,247  

Impairments

           4             132             136  

Taxes other than income taxes

           57             123             180  

Accretion on discounted liabilities

           12             97             109  

Interest and debt expense

     124       134       55       137       (169     281  

Foreign currency transaction (gains) losses

     (44     2       312       (254           16  

 

 

Total Costs and Expenses

     83       3,152       367       4,317       (680     7,239  

 

 

Loss before income taxes

     (1,492     (1,733     (311     (1,160     2,472       (2,224

Income tax benefit

     (23     (306     (18     (421           (768

 

 

Net loss

     (1,469     (1,427     (293     (739     2,472       (1,456

Less: net income attributable to noncontrolling interests

                       (13           (13

 

 

Net Loss Attributable to ConocoPhillips

   $ (1,469     (1,427     (293     (752     2,472       (1,469

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ (368     (326     (47     445       (72     (368

 

 

 

26


Table of Contents
                                                                                         
     Millions of Dollars  
     March 31, 2017  
Balance Sheet    ConocoPhillips     ConocoPhillips
Company
     ConocoPhillips
Canada
Funding
Company I
    All Other
Subsidiaries
     Consolidating
Adjustments
    Total
Consolidated
 

Assets

              

Cash and cash equivalents

   $       313        58       2,738              3,109  

Short-term investments

                        252              252  

Accounts and notes receivable

     12       1,814        25       3,876        (2,368     3,359  

Inventories

           142              955              1,097  

Prepaid expenses and other current assets

     1       155        7       2,773        (25     2,911  

 

 

Total Current Assets

     13       2,424        90       10,594        (2,393     10,728  

Investments, loans and long-term receivables*

     38,761       62,802        2,280       31,145        (113,313     21,675  

Net properties, plants and equipment

           5,818              48,622              54,440  

Other assets

     40       2,345        216       1,271        (2,742     1,130  

 

 

Total Assets

   $ 38,814       73,389        2,586       91,632        (118,448     87,973  

 

 

Liabilities and Stockholders’ Equity

              

Accounts payable

   $       2,356        2       3,541        (2,368     3,531  

Short-term debt

     (9     999        6       99              1,095  

Accrued income and other taxes

           61              695              756  

Employee benefit obligations

           336              129              465  

Other accruals

     101       259        49       1,295        (25     1,679  

 

 

Total Current Liabilities

     92       4,011        57       5,759        (2,393     7,526  

Long-term debt

     8,173       12,635        1,708       2,824              25,340  

Asset retirement obligations and accrued environmental costs

           944              6,940              7,884  

Deferred income taxes

                        9,778        (2,210     7,568  

Employee benefit obligations

           1,906              628              2,534  

Other liabilities and deferred credits*

     1,758       9,927        778       14,240        (25,183     1,520  

 

 

Total Liabilities

     10,023       29,423        2,543       40,169        (29,786     52,372  

Retained earnings

     25,280       14,672        (580     13,253        (20,821     31,804  

Other common stockholders’ equity

     3,511       29,294        623       37,962        (67,841     3,549  

Noncontrolling interests

                        248              248  

 

 

Total Liabilities and Stockholders’ Equity

   $ 38,814       73,389        2,586       91,632        (118,448     87,973  

 

 

*Includes intercompany loans.

              
Balance Sheet    December 31, 2016  

Assets

              

Cash and cash equivalents

   $       358        13       3,239              3,610  

Short-term investments

                        50              50  

Accounts and notes receivable

     22       1,968        23       6,103        (4,702     3,414  

Inventories

           84              934              1,018  

Prepaid expenses and other current assets

     2       116        8       415        (24     517  

 

 

Total Current Assets

     24       2,526        44       10,741        (4,726     8,609  

Investments, loans and long-term receivables*

     37,901       64,434        2,296       31,643        (114,602     21,672  

Net properties, plants and equipment

           6,301              52,030              58,331  

Other assets

     40       2,194        220       1,240        (2,534     1,160  

 

 

Total Assets

   $ 37,965       75,455        2,560       95,654        (121,862     89,772  

 

 

Liabilities and Stockholders’ Equity

              

Accounts payable

   $       4,683        1       3,671        (4,702     3,653  

Short-term debt

     (10     999        6       94              1,089  

Accrued income and other taxes

           85              399              484  

Employee benefit obligations

           489              200              689  

Other accruals

     171       271        40       536        (24     994  

 

 

Total Current Liabilities

     161       6,527        47       4,900        (4,726     6,909  

Long-term debt

     8,975       12,635        1,710       2,866              26,186  

Asset retirement obligations and accrued environmental costs

           925              7,500              8,425  

Deferred income taxes

                        10,972        (2,023     8,949  

Employee benefit obligations

           1,901              651              2,552  

Other liabilities and deferred credits*

     417       10,391        748       17,832        (27,863     1,525  

 

 

Total Liabilities

     9,553       32,379        2,505       44,721        (34,612     54,546  

Retained earnings

     25,025       14,015        (541     12,883        (19,834     31,548  

Other common stockholders’ equity

     3,387       29,061        596       37,798        (67,416     3,426  

Noncontrolling interests

                        252              252  

 

 

Total Liabilities and Stockholders’ Equity

   $ 37,965       75,455        2,560       95,654        (121,862     89,772  

 

 

*Includes intercompany loans.

              

 

27


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

   $ (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  

 

 
Statement of Cash Flows    Three Months Ended March 31, 2016  

Cash Flows From Operating Activities

             

Net Cash Provided by (Used in) Operating Activities

   $ (153     (284     1        1,011       (154     421  

 

 

Cash Flows From Investing Activities

             

Capital expenditures and investments

           (504            (1,516     199       (1,821

Working capital changes associated with investing activities

           (21            (113           (134

Proceeds from asset dispositions

     2,300       60              75       (2,300     135  

Net sales (purchases) of short-term investments

                        (302           (302

Long-term advances/loans—related parties

           (51                  51        

Collection of advances/loans—related parties

                        2,198       (2,145     53  

Intercompany cash management

     (3,438     3,206              232              

Other

           8              (4           4  

 

 

Net Cash Provided by (Used in) Investing Activities

     (1,138     2,698              570       (4,195     (2,065

 

 

Cash Flows From Financing Activities

             

Issuance of debt

     1,600       2,994              51       (51     4,594  

Repayment of debt

           (2,145            (64     2,145       (64

Issuance of company common stock

     7                          (49     (42

Dividends paid

     (313                  (203     203       (313

Other

     (3     (2,320            184       2,101       (38

 

 

Net Cash Provided by (Used in) Financing Activities

     1,291       (1,471            (32     4,349       4,137  

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

                        5             5  

 

 

Net Change in Cash and Cash Equivalents

           943       1        1,554             2,498  

Cash and cash equivalents at beginning of period

           4       15        2,349             2,368  

 

 

Cash and Cash Equivalents at End of Period

   $       947       16        3,903             4,866  

 

 

 

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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 48.

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

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. 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 13,100 employees worldwide and total assets of $88 billion as of March 31, 2017.

Overview

Despite increases since the fourth quarter of 2016, global production oversupply caused commodity prices to remain challenged in the first quarter of 2017.

In the fourth quarter of 2016, given our view that commodity prices were likely to remain lower and more volatile, we announced an updated value proposition. Our value proposition principles, which are to maintain a strong investment grade balance sheet, grow our dividend and pursue disciplined growth, remained essentially unchanged; however, we took steps to improve our competitiveness and resilience by establishing clear priorities for allocating future cash flows. In order, those priorities are: invest capital at a level that maintains flat production volumes and pay our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares; and invest capital to grow absolute production. In conjunction with updating our value proposition, we outlined a 2017 to 2019 operating plan that achieves our cash allocation priorities at Brent prices at or above $50 per barrel with asset sales of $5 billion to $8 billion.

In the first quarter of 2017, we made significant progress toward delivering on our priorities. We increased our quarterly dividend by 6 percent to $0.265 per share, made a prepayment of $805 million on our term loan due in 2019, and repurchased 2.2 million shares of our common stock.    

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) oil sands partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the

 

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date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment. The cash portion of the consideration is subject to customary adjustments. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars for every $1 Canadian dollar by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 Canadian dollars per barrel. With the proceeds from this deal, we plan to significantly accelerate our value proposition by reducing debt to $20 billion and tripling our annual planned share buybacks from $1 billion to $3 billion, both in 2017. On a longer-term basis, this will result in a targeted debt level of $15 billion and repurchases of up to $6 billion of our common stock by year-end 2019.

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary closing adjustments. The six-year contingent payment is effective beginning January 1, 2018, and is due annually for periods in which the monthly U.S. Henry Hub (HH) price is at or above $3.20 per million British thermal units (MMBTU). Proceeds from this transaction will be used for general corporate purposes.

For additional information on our dispositions, see Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.

Our recently announced asset dispositions are in line with our strategy, announced in November 2016, to focus on low cost-of-supply projects in our portfolio that strategically fit our development plans. We are focused on delivering on our value proposition, and are aggressively executing on our stated plans, which we believe position the company for success in the current environment of price uncertainty and ongoing volatility.

Operationally, we continue to focus on safely executing our capital program and remaining attentive to our costs. We produced 1,593 thousand barrels of oil equivalent per day (MBOED) in the first quarter of 2017, an increase of 15 MBOED compared with the same period of 2016. We continue to pursue sustainable operating cost reductions within our business. Operating costs include production and operating expense; selling, general and administrative expense; and exploration general and administrative, geological and geophysical, lease rental and other expense.

Business Environment

Global oil market conditions remain challenged but are improving. Global market fundamentals are trending toward a better balance; however, it will take time for the high level of global inventories to drop to more normal levels.

Global oil prices experienced elevated levels of volatility throughout 2016 with first quarter Brent crude oil prices reaching a 10-year quarterly average low of $33.89 per barrel. Global oil prices began to improve at the end of 2016 and through the first quarter of 2017 in response to stronger global demand and slower production growth.

The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by 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.

 

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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 HH natural gas:

 

LOGO

Brent crude oil prices averaged $53.78 per barrel in the first quarter of 2017, an increase of 59 percent compared with $33.89 per barrel in the first quarter of 2016, and an increase of 9 percent compared with $49.46 in the fourth quarter of 2016. Industry crude prices for WTI averaged $51.83 per barrel in the first quarter of 2017, an increase of 56 percent compared with $33.27 per barrel in the first quarter of 2016, and an increase of 5 percent compared with $49.18 in the fourth quarter of 2016.

Henry Hub natural gas prices averaged $3.32 per MMBTU in the first quarter of 2017, an increase of 59 percent compared with $2.09 per MMBTU in the first quarter of 2016, and an increase of 11 percent compared with $2.98 per MMBTU in the fourth quarter of 2016. Prices improved relative to the same period of 2016 as a result of growth in demand for natural gas coupled with reduced production.

Our realized bitumen price increased from $1.74 per barrel in the first quarter of 2016 to $21.56 per barrel in the same period of 2017, primarily due to the significant increase in the WCS benchmark price as a result of increases to WTI pricing, partly offset by higher diluent costs. Compared with $21.64 per barrel in the fourth quarter of 2016, our first-quarter 2017 realized bitumen price was essentially flat.

Our total average realized price was $36.18 per barrel of oil equivalent (BOE) in the first quarter of 2017, an increase of 58 percent compared with $22.94 per BOE in the first quarter of 2016, reflecting increased average realized prices for all commodities.

 

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Key Operating and Financial Summary

Significant items during the first quarter of 2017 included the following:

 

   

Achieved first-quarter production excluding Libya of 1,584 MBOED; 2 percent production growth adjusted for downtime and dispositions.

   

Reduced production and operating expenses by 4 percent year over year.

   

Increased quarterly dividend by 6 percent.

   

Announced strategic Canadian and San Juan Basin asset dispositions in March and April, respectively, for total consideration of approximately $16 billion.

   

Strengthened balance sheet through $0.8 billion of early debt retirement; announced revised debt target of $15 billion by year-end 2019.

   

Progressed share buyback program and increased authorization to $6 billion.

Outlook

Capital and Production Guidance

Second-quarter 2017 production is expected to be 1,495 to 1,535 MBOED, excluding Libya and the impacts of our recently announced Canada and San Juan dispositions.

Full-year 2017 production and capital expenditures guidance, excluding the impacts from the Canada and San Juan Basin dispositions, are unchanged.

Marketing Activities

In line with our strategic objectives, we are currently marketing certain noncore assets primarily associated with North American natural gas. Given our recently announced agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion, we have adjusted our outlook on total consideration from asset dispositions from the previously-stated range of $5 billion to $8 billion over the next two years, to more than $16 billion in 2017. On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million.

Restructuring Costs

In the first quarter of 2017, we recorded a before-tax gross severance accrual of $39 million, primarily due to our recently announced Canada disposition. We expect to incur additional restructuring charges during the remainder of 2017 due to our aforementioned Canada and San Juan dispositions. As the analysis is ongoing, it is not reasonably practicable to quantify the financial impact, but the impact could be material to our results of operations for the periods in which the restructuring costs are incurred.

Impairments

As we continue to market certain noncore assets, primarily associated with North American natural gas, it is reasonably likely we will incur future impairment charges. Within our Lower 48 segment, we expect to record an estimated noncash before-tax impairment of approximately $3 billion in the second quarter of 2017 associated with the announced disposition of our interests in the San Juan Basin.

While we may incur additional future impairment charges to investments in nonconsolidated entities accounted for under the equity method and long-lived assets, it is not reasonably practicable to quantify their financial impacts. These impacts could be material to our results of operations for the periods in which they are incurred.

 

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2017, is based on a comparison with the corresponding period of 2016.

Consolidated Results

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

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Alaska

   $ (11     (2

Lower 48

     (362     (820

Canada

     948       (294

Europe and North Africa

     171       (51

Asia Pacific and Middle East

     236       (5

Other International

     (48     (24

Corporate and Other

     (348     (273

 

 

Net income (loss) attributable to ConocoPhillips

   $ 586       (1,469

 

 

Net income (loss) attributable to ConocoPhillips increased $2,055 million in the first quarter of 2017, compared with the same period of 2016, mainly due to:

 

   

Recognition of deferred tax benefits totaling $996 million primarily related to the expected disposition of certain Canadian assets.

   

Higher realized commodity prices.

   

Improved equity earnings, mainly due to higher realized prices and sales volumes.

   

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

The increase in income was partly offset by higher production taxes and property taxes; proved property impairment expense, primarily in our Alaska segment; and exploration expenses.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues increased 47 percent in the first quarter of 2017, mainly due to higher realized prices across all commodities.

Equity in earnings (losses) of affiliates increased 234 percent in the first quarter of 2017. The increase in earnings was primarily due to higher realized commodity prices, primarily at FCCL, and increased volumes at Australia Pacific LNG Pty Ltd (APLNG) given the ramp-up of Trains 1 and 2.

Purchased commodities increased 43 percent in the first quarter of 2017, largely as a result of higher natural gas prices.

 

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Exploration expenses increased 9 percent in the first quarter of 2017. Exploration expenses increased primarily due to higher dry hole costs, partly offset by reduced leasehold impairment expense.

Dry hole costs increased mainly due to charges totaling $291 million in the first quarter of 2017 for multiple wells in Shenandoah, including wells previously suspended. The increase in dry hole costs was partly offset by the absence of a $110 million before-tax charge in 2016 for the Melmar prospect in deepwater Gulf of Mexico.

Leasehold impairment expense was reduced mainly due to the absence of 2016 before-tax charges of $95 million for our Melmar leasehold and $73 million for various Gulf of Mexico leases after completion of an initial marketing effort. The reduction was partly offset by a before-tax charge of $51 million for Shenandoah in deepwater Gulf of Mexico.

For additional information on leasehold impairments and other exploration expenses, see Note 6—Suspended Wells and Other Exploration Expenses, and Note 7—Impairments, in the Notes to Consolidated Financial Statements.

DD&A decreased 12 percent in the first quarter of 2017, mainly due to lower unit-of-production rates from reserves revisions, as well as lower volumes. The impacts of these drivers to DD&A expense were most significant in our Lower 48 segment.

 

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Summary Operating Statistics

 

                             
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

Average Net Production

  

Crude oil (MBD)*

     601        617  

Natural gas liquids (MBD)

     134        146  

Bitumen (MBD)

     223        166  

Natural gas (MMCFD)**

     3,809        3,895  

 

 

Total Production (MBOED)***

     1,593        1,578  

 

 
     Dollars Per Unit  

Average Sales Prices

     

Crude oil (per barrel)

   $ 50.97        31.47  

Natural gas liquids (per barrel)

     24.87        12.30  

Bitumen (per barrel)

     21.56        1.74  

Natural gas (per thousand cubic feet)

     3.84        2.99  

 

 
     Millions of Dollars  

Exploration Expenses

     

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

   $ 145        145  

Leasehold impairment

     63        180  

Dry holes

     343        180  

 

 
   $ 551        505  

 

 

    *Thousands of barrels per day.

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

***Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2017, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production from operations increased 1 percent in the first quarter of 2017 compared with the same period of 2016. The increase in total average production primarily resulted from additional production from major developments, including tight oil plays in the Lower 48; Surmont 2 and FCCL in Canada; APLNG in Australia; the Kebabangan gas field in Malaysia; the Western North Slope in Alaska; and the Greater Britannia Area in the United Kingdom. Improved drilling and well performance in Canada, Norway, Alaska, and China, as well as lower unplanned downtime in the Lower 48 and resumed production in Libya, also contributed to the increase in production. The production increase was partly offset by normal field decline; the loss of 36 MBOED attributable to noncore assets disposed in 2016, including our working interest in the offshore South Natuna Sea Block B Production Sharing Contract (PSC) in Indonesia; royalty rate impacts in Canada; and PSC impacts in Indonesia and Malaysia. In the first quarter of 2017, we achieved production of 1,593 MBOED. Excluding production from Libya, first quarter production was 1,584 MBOED. Adjusted for the net impact from dispositions of 36 MBOED and reduced downtime of 18 MBOED, our production increased by 24 MBOED, or 2 percent, compared with the first quarter of 2016.

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets. Production associated with these assets was 279 MBOED and 258 MBOED in the first quarters of 2017 and 2016, respectively. The transaction is subject to specific conditions being satisfied, including regulatory review, and is expected to close in the second quarter of 2017. On April 12, 2017, we signed a definitive agreement to sell our interests in the San

 

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Juan Basin, which produced 111 MBOED and 122 MBOED in the first quarters of 2017 and 2016, respectively. The transaction is subject to specific conditions being satisfied, including regulatory review, and is expected to close in the third quarter of 2017. Year-end 2016 reserves associated with our Canadian transaction and San Juan Basin assets being disposed were 1.3 billion barrels of oil equivalent (BBOE) and 0.6 BBOE, respectively.

Segment Results

Alaska

                             
       Three Months Ended
March 31
 
       2017        2016  
    

 

 

 

Net Loss Attributable to ConocoPhillips (millions of dollars)

     $ (11        (2

 

 

Average Net Production

         

Crude oil (MBD)

       175          170  

Natural gas liquids (MBD)

       15          14  

Natural gas (MMCFD)

       7          38  

 

 

Total Production (MBOED)

       191          191  

 

 

Average Sales Prices

         

Crude oil (dollars per barrel)

     $ 52.09          32.54  

Natural gas (dollars per thousand cubic feet)

       3.53          4.84  

 

 

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of March 31, 2017, Alaska contributed 20 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Losses from Alaska increased by $9 million in the first quarter of 2017, compared with the same period of 2016. The increase in losses was primarily due to a $110 million after-tax impairment charge for the associated properties, plants and equipment carrying value of our small interest in a nonoperated producing property. Additionally, losses increased due to a state deferred tax asset valuation allowance; higher exploration expense, primarily from increased seismic activity in the Western North Slope and higher dry hole costs; higher DD&A, mainly due to increased capital additions; and increased property taxes resulting from the absence of a settlement ruling which lowered taxes in 2016. The increase in losses was largely offset by higher crude oil realized prices in the first quarter of 2017.

Average production in the first quarter of 2017 was flat compared with the corresponding period of 2016, as the impact of normal field decline and our 2016 noncore asset dispositions was offset by new production in the Western North Slope, Greater Prudhoe and Greater Kuparuk areas, as well as improved base production performance.

 

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Lower 48

 

                             
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Net Loss Attributable to ConocoPhillips (millions of dollars)

   $ (362     (820

 

 

Average Net Production

    

Crude oil (MBD)

     176       202  

Natural gas liquids (MBD)

     75       86  

Natural gas (MMCFD)

     1,116       1,216  

 

 

Total Production (MBOED)

     437       491  

 

 

Average Sales Prices

    

Crude oil (dollars per barrel)

   $ 45.89       27.04  

Natural gas liquids (dollars per barrel)

     22.07       9.45  

Natural gas (dollars per thousand cubic feet)

     2.83       1.80  

 

 

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties and exploration activities in the Gulf of Mexico. As of March 31, 2017, the Lower 48 contributed 26 percent of our worldwide liquids production and 29 percent of our worldwide natural gas production.

Losses from Lower 48 decreased 56 percent in the first quarter of 2017, compared with the same period of 2016 primarily due to:

 

   

Higher realized crude oil, natural gas and natural gas liquids prices.

   

Lower DD&A expense, mainly due to a lower unit-of-production rate from reserve additions, as well as lower volumes.

   

Lower exploration expenses, including the absence of 2016 after-tax leasehold impairment charges of $62 million and $47 million related to our Melmar leasehold and certain other leases in the Gulf of Mexico, respectively, as well as the absence of a $71 million after-tax dry hole charge in 2016 for the Melmar prospect. The reduction in expense was partly offset by dry hole costs and a leasehold impairment charge in the first quarter of 2017 associated with Shenandoah.

   

Lower production and operating expenses, mainly due to cost efficiencies.

The decrease in losses was partly offset by lower crude oil, natural gas and natural gas liquids sales volumes.

In the first quarter of 2017, our average realized crude oil price of $45.89 per barrel was 11 percent less than WTI of $51.83 per barrel. The differential is driven primarily by local market dynamics in the Gulf Coast and Bakken, and may remain relatively wide in the near term.

Total average production decreased 11 percent in the first quarter of 2017, compared with the first quarter of 2016. The decrease in total production was mainly attributable to normal field decline, partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin, as well as the absence of the impacts of a third-party gas plant fire in 2016.

Asset Disposition Update

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary closing adjustments. We expect to record an estimated noncash before-tax impairment on the assets of approximately $3 billion in the second quarter of

 

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2017. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017. See Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Canada

 

                             
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

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

   $ 948        (294

 

 

Average Net Production

     

Crude oil (MBD)

     6        8  

Natural gas liquids (MBD)

     23        25  

Bitumen (MBD)

     

Consolidated operations

     52        27  

Equity affiliates

     171        139  

 

 

Total bitumen

     223        166  

Natural gas (MMCFD)

     488        566  

 

 

Total Production (MBOED)

     333        293  

 

 

Average Sales Prices

     

Crude oil (dollars per barrel)

   $ 43.82        26.11  

Natural gas liquids (dollars per barrel)

     21.32        11.69  

Bitumen (dollars per barrel)

     

Consolidated operations

     15.63        2.54  

Equity affiliates

     23.63        1.59  

Total bitumen

     21.56        1.74  

Natural gas (dollars per thousand cubic feet)

     1.95        1.20  

 

 

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. As of March 31, 2017, Canada contributed 26 percent of our worldwide liquids production and 13 percent of our worldwide natural gas production.

Earnings from Canada increased by $1,242 million in the first quarter of 2017, compared with the same period of 2016, primarily due to the recognition of $996 million in deferred tax benefits related to the capital gains component of the expected disposition of certain Canadian assets further discussed below and the recognition of previously unrealizable Canadian tax basis. Additionally, earnings increased due to higher realized prices across all commodities.

Total average production increased 14 percent in the first quarter of 2017, compared with the same period of 2016. The production increase was primarily due to production ramp-ups and well performance at Surmont 2 and FCCL, partly offset by price-related royalty rate impacts, normal field decline, and the impacts of a fire at Syncrude’s Mildred Lake Upgrader which provides synthetic crude to Surmont for blending as diluent.

Asset Disposition Update

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second

 

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quarter of 2017. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment due during periods in which the WCS crude prices exceed $52 Canadian dollars per barrel. The cash portion of the consideration is subject to customary adjustments. Based on Cenovus’ share price on March 31, 2017, we expect to record an estimated gain on sale of approximately $2 billion, upon closing, which is expected in the second quarter of 2017. The amount of actual gain recognized may differ from our estimate, subject to post-closing adjustments and Cenovus’ share price and exchange rates on the date of close. See Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Europe and North Africa

 

                             
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

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

   $ 171        (51

 

 

Average Net Production

     

Crude oil (MBD)

     140        125  

Natural gas liquids (MBD)

     9        7  

Natural gas (MMCFD)

     544        507  

 

 

Total Production (MBOED)

     240        216  

 

 

Average Sales Prices

     

Crude oil (dollars per barrel)

   $ 53.34        35.47  

Natural gas liquids (dollars per barrel)

     31.21        18.78  

Natural gas (dollars per thousand cubic feet)

     5.86        5.03  

 

 

The Europe and North Africa segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, the Norwegian Sea, and Libya. As of March 31, 2017, our Europe and North Africa operations contributed 16 percent of our worldwide liquids production and 14 percent of our worldwide natural gas production.

Earnings for Europe and North Africa operations increased $222 million in the first quarter of 2017, compared with the same period of 2016. The earnings increase was primarily due to higher crude oil, natural gas and natural gas liquids realized prices; the absence of 2016 after-tax proved property impairments in the United Kingdom of $60 million; and lower DD&A, mainly due to foreign currency impacts in the United Kingdom.

Average production increased 11 percent in the first quarter of 2017, compared with the corresponding period of 2016. The increase was mainly due to improved drilling and well performance in Norway; new production from the Greater Ekofisk and Greater Britannia areas; the resumption of production in Libya, where we had four crude liftings in the first quarter of 2017; and higher Norway gas offtake. The increased production was partly offset by normal field decline in Norway and the United Kingdom.

 

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Asia Pacific and Middle East

 

                             
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

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

   $ 236        (5

 

 

Average Net Production

     

Crude oil (MBD)

     

Consolidated operations

     91        100  

Equity affiliates

     13        12  

 

 

Total crude oil

     104        112  

 

 

Natural gas liquids (MBD)

     

Consolidated operations

     5        7  

Equity affiliates

     7        7  

 

 

Total natural gas liquids

     12        14  

 

 

Natural gas (MMCFD)

     

Consolidated operations

     719        769  

Equity affiliates

     935        799  

 

 

Total natural gas

     1,654        1,568  

 

 

Total Production (MBOED)

     392        387  

 

 

Average Sales Prices

     

Crude oil (dollars per barrel)

     

Consolidated operations

   $ 53.74        33.11  

Equity affiliates

     55.58        33.50  

Total crude oil

     53.98        33.15  

Natural gas liquids (dollars per barrel)

     

Consolidated operations

     42.96        27.62  

Equity affiliates

     43.20        27.45  

Total natural gas liquids

     43.10        27.54  

Natural gas (dollars per thousand cubic feet)

     

Consolidated operations

     4.96        4.24  

Equity affiliates

     4.00        3.56  

Total natural gas

     4.42        3.90  

 

 

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Brunei. As of March 31, 2017, Asia Pacific and Middle East contributed 12 percent of our worldwide liquids production and 43 percent of our worldwide natural gas production.

Earnings increased by $241 million in the first quarter of 2017, compared with the same period of 2016, primarily due to higher realizations across all commodities, including LNG and crude oil which improved our equity earnings from APLNG and Qatar Liquefied Gas Company Limited (3) (QG3), respectively, and higher sales volumes mainly at APLNG. The earnings increase was partly offset by higher DD&A expense and increased power costs from Trains 1 and 2 being online at APLNG.

 

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Average production increased 1 percent in the first quarter of 2017, compared with the same period of 2016, mainly due to new production from the ramp-up of APLNG in Australia and the Kebabangan gas field in Malaysia, and improved drilling and well performance in China. The production increase was partly offset by the disposition of our working interest in the offshore South Natuna Sea Block B PSC in Indonesia; PSC impacts in Indonesia, Malaysia and Australia; and normal field decline in China.

Other International

 

                             
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Net Loss Attributable to ConocoPhillips (millions of dollars)

   $ (48     (24

 

 

The Other International segment consists of exploration activities in Colombia and Chile.

Losses from our Other International operations increased $24 million in the first quarter of 2017, compared with the same period of 2016. The increase in losses was primarily due to a $28 million after-tax charge for the cancellation of our Athena drilling rig contract in the first quarter of 2017.

Corporate and Other

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017     2016  
  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips

    

Net interest

   $ (253     (222

Corporate general and administrative expenses

     (93     (85

Technology

     9       21  

Other

     (11     13  

 

 
   $ (348     (273

 

 

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased by $31 million in the first quarter of 2017, compared with the same period of 2016, primarily due to lower capitalized interest on projects, higher interest expense, and impacts from the fair market value method of apportioning interest expense in the United States.

Corporate general and administrative expenses increased by $8 million in the first quarter of 2017, compared with the same period of 2016, primarily due to increases from market impacts on certain compensation programs and staff costs, partly offset by lower pension settlement expense.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on tight oil reservoirs, heavy oil and oil sands, as well as LNG. Earnings from Technology decreased $12 million in the first quarter of 2017, compared with the same period of 2016. The decrease was primarily due to lower licensing revenues, partly offset by reduced technology program spend.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation and other costs not directly associated with an operating segment. “Other” expenses increased by $24 million in the first quarter of 2017, mainly due to foreign currency impacts.

 

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

 

                             
     Millions of Dollars  
     March 31
2017
    December 31
2016
 
  

 

 

 

Short-term debt

   $ 1,095       1,089  

Total debt

     26,435       27,275  

Total equity

     35,601       35,226  

Percent of total debt to capital*

     43     44  

Percent of floating-rate debt to total debt

     6     9  

 

 

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities. We rely on cash flows from operating activities, proceeds from asset sales, our commercial paper and credit facility programs, and our shelf registration statement to support short- and long-term liquidity requirements. The primary uses of our available cash were $966 million to support our ongoing capital expenditures and investments program, $331 million to pay dividends, $112 million to repurchase common stock, and $203 million net purchases of short-term investments. In the first quarter of 2017, we made a prepayment of $805 million on our term loan due in 2019. During the first three months of 2017, cash and cash equivalents decreased by $501 million to $3,109 million.

We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments and required debt payments.

Significant Sources of Capital

Operating Activities

Cash provided by operating activities was $1,790 million for the first three months of 2017, compared with $421 million for the corresponding period of 2016. The increase was primarily due to higher realized prices across all commodities.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Production levels are impacted by such factors as the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. As we undertake cash conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.

 

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Investing Activities

Proceeds from asset sales for the first three months of 2017 were $35 million compared with $135 million for the corresponding period of 2016.

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment triggered during quarterly periods in which the average WCS crude prices exceed $52 Canadian dollars per barrel. The cash portion of the consideration is subject to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second quarter of 2017. On the date of signing, we received a $130 million deposit from Cenovus Energy, which is included in the “Cash Flows From Investing Activities” section in our consolidated statement of cash flows.

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billion of total proceeds including $2.7 billion in cash, subject to customary adjustments, and a contingent payment of up to $300 million. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017.

For additional information on our dispositions, see Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, and the Results of Operations section within Management’s Discussion and Analysis.

Commercial Paper and Credit Facilities

At March 31, 2017, we had a revolving credit facility totaling $6.75 billion, expiring in June 2019. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.25 billion commercial paper program. We also have the ConocoPhillips Qatar Funding Ltd. $500 million commercial paper program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days. We had no commercial paper outstanding at March 31, 2017 or December 31, 2016, under either the ConocoPhillips or the ConocoPhillips Qatar Funding Ltd commercial paper program. We had no direct borrowings or letters of credit issued under the revolving credit facility. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at March 31, 2017.

With recent improved commodity prices, Moody’s Investor Services improved their outlook for our debt from “negative” to “positive” while Fitch and Standard & Poor’s both reflected an improvement from “negative” to “stable” during the first quarter of 2017. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were downgraded, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit rating were to deteriorate to a level

 

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prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2017 and December 31, 2016, we had direct bank letters of credit of $266 million and $304 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of credit ratings downgrades, we may be required to post additional letters of credit.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

For information about guarantees, see Note 10—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Expenditures” section.

Our debt balance at March 31, 2017, was $26.4 billion, a decrease of $0.8 billion from the balance at December 31, 2016, primarily as a result of an $805 million prepayment of our term loan due in 2019. Our short-term debt balance at March 31, 2017, increased $6 million compared with December 31, 2016, primarily as a result of the timing of scheduled maturities.

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to close in the second quarter of 2017. We intend to use a portion of the proceeds to reduce debt to $20 billion in 2017. On a longer-term basis our debt target is $15 billion by year-end 2019. For more information, see Note 4Assets Held for Sale and Other Planned Dispositions and Note 8—Debt, in the Notes to Consolidated Financial Statements.

In January 2017, we announced a 6 percent increase in the quarterly dividend to $0.265 per share. The dividend was paid March 1, 2017, to stockholders of record at the close of business on February 14, 2017.

On November 10, 2016, our Board of Directors authorized the purchase of up to $3 billion of our common stock over the next three years. During the first quarter of 2017, our Board of Directors approved an increase in the existing share repurchase authorization to a total of $6 billion, with an expectation of $3 billion occurring in 2017 and the remaining $3 billion allocated to 2018 and 2019. Since our share repurchase program began in November 2016, share repurchases totaled 4.8 million shares at a cost of $238 million through March 31, 2017.

 

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Capital Expenditures

 

                             
     Millions of Dollars  
     Three Months Ended
March 31
 
     2017      2016  
  

 

 

 

Alaska

   $ 228        320  

Lower 48

     343        580  

Canada

     62        254  

Europe and North Africa

     200        303  

Asia Pacific and Middle East

     109        306  

Other International

     5        41  

Corporate and Other

     19        17  

 

 

Capital expenditures and investments

   $ 966        1,821  

 

 

During the first three months of 2017, capital expenditures and investments supported key exploration and development programs, primarily:

 

   

Oil and natural gas development and exploration activities in the Lower 48, including Eagle Ford, Bakken, and the Permian Basin.

   

Alaska activities related to development in the Western North Slope, Greater Kuparuk Area, and the Greater Prudhoe Area.

   

Development activities, in Europe, including the Greater Ekofisk Area, Aasta Hansteen, and Clair Ridge.

   

Continued oil sands development and appraisal activities in liquids-rich plays in Canada.

   

Appraisal drilling in deepwater Gulf of Mexico.

   

Continued development in Malaysia, Indonesia, China and Australia; exploration activity in Malaysia and appraisal activity in Australia.

Contingencies

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and

 

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the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 11—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal Matters

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 63–65 of our 2016 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of March 31, 2017, there were 14 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At March 31, 2017, our balance sheet included a total environmental accrual of $260 million, compared with $247 million at December 31, 2016, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our

 

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operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-ba