ConocoPhillips is an international energy company and is considered the third largest US oil company.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended March 31, 2016
or
For the transition period from to
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
600 North Dairy Ashford, Houston, TX 77079
(Address of principal executive offices) (Zip Code)
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 x 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 x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The registrant had 1,238,387,216 shares of common stock, $.01 par value, outstanding at March 31, 2016.
CONOCOPHILLIPS
TABLE OF CONTENTS
Part I—Financial Information
Item 1. Financial Statements
Consolidated Income Statement
Consolidated Statement of Comprehensive Income
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplementary Information—Condensed Consolidating Financial Information
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II—Other Information
Item 1A. Risk Factors
Item 6. Exhibits
Signature
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Gain on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Loss before income taxes
Income tax benefit
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Diluted
Dividends Paid Per Share of Common Stock (dollars)
Average Common Shares Outstanding (in thousands)
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Net Income (Loss)
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income
Net actuarial loss arising during the period
Reclassification adjustment for amortization of net actuarial losses included in net income
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Foreign currency translation adjustments
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Loss
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Loss Attributable to ConocoPhillips
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Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable (net of allowance of $6 million in 2016 and $7 million in 2015)
Accounts and notes receivable—related parties
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $73,521 million in 2016 and $70,413 million in 2015)
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2016—1,780,617,889 shares; 2015—1,778,226,388 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2016—542,230,673 shares; 2015—542,230,673 shares)
Accumulated other comprehensive loss
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
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Cash Flows From Operating Activities
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Dry hole costs and leasehold impairments
Deferred taxes
Distributions received greater than equity losses
Other
Working capital adjustments
Decrease in accounts and notes receivable
Decrease in inventories
Decrease in prepaid expenses and other current assets
Decrease in accounts payable
Decrease in taxes and other accruals
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Purchases of short-term investments
Collection of advances/loans—related parties
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Dividends paid
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
*Certain amounts have been reclassified to conform to current-period presentation. See Note 16–Cash Flow Information, in the Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
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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 2015 Annual Report on Form 10-K.
Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Certain financial information has been revised for all prior periods presented to reflect the change in the composition of our operating segments. For additional information, see Note 19—Segment Disclosures and Related Information.
Note 2—Change in Accounting Principles
We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-02, “Amendments to the Consolidation Analysis,” beginning January 1, 2016. The ASU amends existing requirements applicable to reporting entities that are required to evaluate whether certain legal entities, including variable interest entities (VIEs), should be consolidated. The adoption of this ASU did not have an impact on our consolidated financial statements and disclosures. See Note 3—Variable Interest Entities, for additional information on our significant VIE.
Note 3—Variable Interest Entities
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIE 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, 2016, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, for additional information.
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Note 4—Inventories
Inventories consisted of the following:
Crude oil and natural gas
Materials and supplies
Inventories valued on the last-in, first-out (LIFO) basis totaled $271 million and $317 million at March 31, 2016 and December 31, 2015, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $29 million and $6 million at March 31, 2016 and December 31, 2015, respectively.
Note 5—Assets Held for Sale
On April 22, 2016, we sold our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet for $134 million, net of settlement of gas imbalances and customary adjustments. At March 31, 2016, the net carrying value of our Beluga River Unit interest, which is included in the Alaska segment, was $78 million, consisting primarily of $100 million of property, plant and equipment (PP&E) and $19 million of asset retirement obligations (ARO). Accordingly, $100 million of PP&E was classified as held for sale and included in the “Prepaid expenses and other current assets” line on our consolidated balance sheet as of March 31, 2016.
Note 6—Investments, Loans and Long-Term Receivables
APLNG
APLNG’s $8.5 billion project finance facility consists of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. At March 31, 2016, $8.4 billion had been drawn from 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. See Note 11—Guarantees, for additional information.
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 3—Variable Interest Entities, for additional information.
Following the fourth quarter 2015 impairment of our investment in APLNG, the outlook for crude oil and natural gas prices continued to deteriorate. As a result, the estimated fair value of our investment in APLNG declined to an amount below book value during the first quarter of 2016. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment was not other than temporary under the guidance of FASB Accounting Standards Codification (ASC) Topic 323, “Investments—Equity Method and Joint Ventures.” 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 book value has been less than market value since our impairment in the fourth quarter of 2015. Fair value has been estimated based on an internal discounted cash flow model using estimates of future production, prices from futures exchanges and pricing service companies, costs, foreign currency rates, and a discount factor believed to be consistent with those used by principal market participants.
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At March 31, 2016, the fair value of our investment in APLNG was estimated to be $9,878 million, resulting in an unrecognized impairment of $437 million. We will continue to monitor the relationship between the book value and the fair value of APLNG. Should we determine in the future there has been a loss in the book 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 book value and fair value as of the end of the reporting period.
At March 31, 2016, the book value of our equity method investment in APLNG was $10,315 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.
FCCL
At March 31, 2016, the book value of our equity method investment in FCCL was $8,759 million, net of a $1,333 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.
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, 2016, significant loans to affiliated companies included $750 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 7—Suspended Wells
The capitalized cost of suspended wells at March 31, 2016, was $1,327 million, an increase of $67 million from $1,260 million at year-end 2015. No suspended wells were charged to dry hole expense during the first three months of 2016 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2015.
Note 8—Impairments
During the three-month periods of 2016 and 2015, we recognized the following before-tax impairment charges:
Lower 48
Europe and North Africa
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.
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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 2016, due to lack of commerciality of a recently drilled well, we recorded a pre-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 our decision announced in 2015 not to conduct further activity on certain Gulf of Mexico leases and the completion of an initial marketing effort, we recorded impairments of $73 million in our Lower 48 segment, primarily as a result of changes in the estimated market value.
Note 9—Debt
On March 28, 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 to $6.75 billion. We have two commercial paper programs supported by our $6.75 billion revolving credit facility: the ConocoPhillips $6.1 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $900 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.
At March 31, 2016 and December 31, 2015, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of March 31, 2016 or December 31, 2015. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, $750 million of commercial paper was outstanding at March 31, 2016, compared with $803 million at December 31, 2015. In April 2016, we repaid an additional $640 million of the outstanding commercial paper and expect the remaining commercial paper to be repaid in the second quarter of 2016. Since we had $750 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at March 31, 2016.
On March 3, 2016, we issued notes consisting of:
The $1,250 million of 4.20% Notes due 2021.
The $1,250 million of 4.95% Notes due 2026.
The $500 million of 5.95% Notes due 2046.
In addition, on March 18, 2016, we entered into a $1,600 million three-year senior unsecured term loan facility. Borrowings will accrue interest at a base rate or, for certain euro-denominated borrowings, the London Interbank Offered Rate (LIBOR), in each case plus a margin that is set based on our corporate credit ratings. The applicable margin for loans bearing interest based on the base rate ranges from 0.50% to 1.00% and the applicable margin for loans bearing interest based on LIBOR ranges from 1.50% to 2.00%. Based on our current corporate credit ratings, the applicable margin for loans accruing interest at the base rate is 0.50% and the applicable margin for loans accruing interest at LIBOR is 1.50%.
The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At March 31, 2016, 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.
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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 net proceeds of the notes and term loan will be used for general corporate purposes.
At March 31, 2016, we held $283 million of certain variable rate demand bonds (VRDBs) 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.
Note 10—Noncontrolling Interests
Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2016 and 2015 was as follows:
Non-
ControllingInterest
Balance at January 1
Dividends
Distributions to noncontrolling interests
Other changes, net*
Balance at March 31
Note 11—Guarantees
At March 31, 2016, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
APLNG Guarantees
At March 31, 2016, we had outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing March 2016 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 two years. Our maximum potential amount of future payments related to this guarantee is approximately $90 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.
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We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones, which we estimate should occur beginning later in 2016. Our maximum exposure at March 31, 2016, is $3.2 billion based upon our pro-rata share of the facility used at that date. At March 31, 2016, the carrying value of this guarantee is approximately $114 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 1 to 26 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $1.1 billion ($1.9 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 30 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $170 million and would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $530 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, a guarantee for our portion of a joint venture’s project finance reserve accounts, and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to eight 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, 2016, was approximately $90 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, 2016, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 12—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 $1.6 billion. At March 31, 2016, the carrying value of this guarantee is
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approximately $98 million and the remaining term is nine years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.
Note 12—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made 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.
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As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At March 31, 2016, our balance sheet included a total environmental accrual of $263 million, compared with $258 million at December 31, 2015, 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 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, 2016, we had performance obligations secured by letters of credit of $339 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. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. On October 10, 2014, we filed a separate arbitration under the rules of the International Chamber of Commerce against PDVSA for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects.
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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. We are awaiting the tribunal’s award.
ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. The arbitration hearing was conducted in Singapore in June 2014 under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. In January 2016, we settled three of the four Timor-Leste tax disputes. In March 2016, we received a decision from the arbitration tribunal on the fourth Timor-Leste tax dispute item.
Note 13—Derivative and Financial Instruments
Derivative Instruments
We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and 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:
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The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
Basis
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:
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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:
We had the following net notional position of outstanding foreign currency exchange derivatives:
Sell U.S. dollar, buy other currencies*
Buy U.S. dollar, sell other currencies**
Buy British pound, sell other currencies***
Financial Instruments
We have certain financial instruments on our consolidated balance sheet related to interest-bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.
Cash
Time deposits
Remaining maturities from 1 to 90 days
Commercial paper
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because
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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 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, 2016 and December 31, 2015, was $136 million and $158 million, respectively. For these instruments, $1 million of collateral was posted as of March 31, 2016, and $2 million of collateral was posted as of December 31, 2015. If our credit rating had been downgraded below investment grade on March 31, 2016, we would be required to post $130 million of additional collateral, either with cash or letters of credit.
Note 14—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:
Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
Level 2: Inputs other than quoted prices that are directly or indirectly observable.
Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1 during 2016 or 2015.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical
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relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.
The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):
Commodity derivatives
Total assets
Total liabilities
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.
March 31, 2016
December 31, 2015
At March 31, 2016 and December 31, 2015, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.
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Non-Recurring Fair Value Measurement
The following table summarizes the fair value hierarchy by major category for assets accounted for at fair value on a non-recurring basis:
Net PP&E (held for use)
Net PP&E held for use is comprised of various producing properties impaired to their individual fair values less costs to sell. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount rate believed to be consistent with those used by principal market participants.
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.
Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.
Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on 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):
Financial assets
Total loans and advances—related parties
Financial liabilities
Total debt, excluding capital leases
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Note 15—Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheet included:
The following table summarizes reclassifications out of accumulated other comprehensive income (loss):
There were no items within accumulated other comprehensive income (loss) related to noncontrolling interests.
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Note 16—Cash Flow Information
Cash Payments (Receipts)
Interest
Income taxes*
In relation to certain working capital changes associated with investing activities, we reclassified $198 million of the “Decrease in accounts payable” line within “Cash Flows From Operating Activities” to the “Working capital changes associated with investing activities” line within “Cash Flows From Investing Activities” for the three months ended March 31, 2015. There was no impact to “Cash and Cash Equivalents at End of Period.”
Note 17—Employee Benefit Plans
Pension and Postretirement Plans
Components of Net Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost (credit)
Recognized net actuarial loss
Settlements
Net periodic benefit cost
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During the first three months of 2016, we contributed $38 million to our domestic benefit plans and $34 million to our international benefit plans. In 2016, we expect to contribute approximately $250 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $130 million to our international qualified and nonqualified pension and postretirement benefit plans.
During the three-month period ended March 31, 2016, we determined lump-sum benefit payments will exceed 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 (loss) as pension settlement expense of $82 million. In conjunction with the recognition of pension settlement expense, the fair market values of pension plan assets were updated, and the pension benefit obligations of the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan were remeasured. At the measurement date, the net pension liability increased by $231 million primarily as a result of a decrease in the discount rate from 4.5 percent to 3.8 percent, resulting in a corresponding decrease to other comprehensive income (loss).
Severance Accrual
The following table summarizes our severance accrual activity for the three-month period ended March 31, 2016:
Balance at December 31, 2015
Accruals
Accrual reversals
Benefit payments
Balance at March 31, 2016
Of the remaining balance at March 31, 2016, $20 million is classified as short-term.
Note 18—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
Significant transactions with our equity affiliates were:
Operating revenues and other income
Purchases
Operating expenses and selling, general and administrative expenses
Net interest income*
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Note 19—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.
Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised for all prior periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial.
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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Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Alaska
Intersegment eliminations
Canada
Asia Pacific and Middle East
Corporate and Other
Consolidated sales and other operating revenues
Other International
Consolidated net income (loss) attributable to ConocoPhillips
Consolidated total assets
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Note 20—Income Taxes
Our effective tax rate for the first quarter of 2016 was 35 percent compared with 180 percent for the first quarter of 2015. The decrease in the effective tax rate was primarily due to the effect of the 2015 U.K. tax law change discussed below, partially offset by losses in higher tax rate jurisdictions in the first quarter of 2016.
In the United Kingdom, legislation was enacted on March 26, 2015, to decrease the overall U.K. upstream corporation tax rate from 62 percent to 50 percent effective January 1, 2015. As a result, a $555 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the “Income tax benefit” line on our consolidated income statement.
Note 21—New Accounting Standards
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (ASUNo. 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),” and in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing.” We are currently evaluating the impact of the adoption of ASU No. 2014-09, as amended, and continue to monitor proposals issued by the FASB to clarify the ASU.
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. We are currently evaluating the impact of the adoption of this ASU.
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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.
In February 2016, ConocoPhillips received a $2.3 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
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Equity in losses of affiliates
Other income (loss)
Intercompany revenues
Net loss
Net Loss Attributable to ConocoPhillips
Comprehensive Income (Loss) Attributable to ConocoPhillips
Equity in earnings of affiliates
Costs and E.xpenses
Income (loss) before income taxes
Income tax provision (benefit)
Net income
Net Income Attributable to ConocoPhillips
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Accounts and notes receivable
Investments, loans and long-term receivables*
Net properties, plants and equipment
Liabilities and Stockholders’ Equity
Retained earnings (losses)
Other common stockholders’ equity
Total Liabilities and Stockholders’ Equity
*Includes intercompany loans.
Other liabilities and deferred credits*
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Net Cash Provided by (Used in) Operating Activities
Long-term advances/loans—related parties
Intercompany cash management
Net Cash Provided by (Used in) Investing Activities
Net sales (purchases) of short-term investments
*Certain amounts have been reclassified to conform to current-period presentation. See Note 16—Cash Flow Information, in the Notes to Consolidated Financial Statements.
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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. Headquartered in Houston, Texas, we had operations and activities in 21 countries, approximately 15,600 employees worldwide and total assets of $100 billion as of March 31, 2016.
Basis of Presentation
Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised for all prior periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial. For additional information, see Note 19—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.
Overview
We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. We have a diverse, low cost of supply resource base and a unique set of producing assets that includes legacy assets in North America, Europe and Asia; North American tight oil assets; resource-rich oil sands assets in Canada; and liquefied natural gas (LNG) assets in Asia Pacific, the Middle East and Alaska. Our value proposition combines unique portfolio attributes with capital allocation principles that include distribution to shareholders, a strong investment grade balance sheet, disciplined allocations and a focus on returns. Our value proposition recognizes that future growth could be on an absolute or a per-share basis, consistent with a disciplined approach to business.
The energy landscape continues to be challenged. Global production oversupply and concerns around future demand growth caused commodity prices to weaken significantly during the first quarter of 2016, following a year of weak prices in 2015. Ongoing uncertainty around the timing of a recovery in prices, coupled with tightening credit capacity across the industry, caused us to take actions to preserve the balance sheet strength and mitigate the impacts of possible weak prices in 2016 and 2017.
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We revised our 2016 operating plan in February 2016, reducing our capital expenditures guidance by 17 percent, from $7.7 billion to $6.4 billion, and reducing our quarterly dividend by 66 percent, to $0.25 per share. These actions, which were prudent given the market environment, will allow us to conserve cash in 2016. During the first quarter of 2016, we issued $3.0 billion of debt and obtained a $1.6 billion three-year term loan to secure sufficient cash and liquidity through the current downturn.
In April 2016, we further reduced the 2016 capital expenditures guidance from $6.4 billion to $5.7 billion, primarily driven by reduced deepwater exploration activity, deferrals and lower costs across the portfolio.
We continue to stay focused on safely executing our capital program and remaining vigilant on costs. In the first quarter of 2016 we produced 1,578 thousand barrels of oil equivalent per day (MBOED), which was at the high end of our guidance range of 1,540 to 1,580 MBOED, due to the ramp up of APLNG and strong well performance. We loaded 11 cargoes from Train 1 of our APLNG project in Australia, progressed additional projects toward startup by the end of the year, and 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 expense excluding dry hole and leasehold impairment expense.
Our capital program is focused on maintaining our asset integrity, completing several projects that are underway and pursuing development programs, primarily around legacy conventional assets. We have significantly reduced activity levels in the North American tight oil plays, including the Eagle Ford, Bakken, Permian, Niobrara and Montney. However, we have retained the flexibility to increase or decrease investment activity in these and other assets, as appropriate.
In the first quarter of 2016, we generated approximately $135 million in proceeds from non-core asset dispositions. We continue to monitor the market and evaluate our assets for opportunities to high-grade our portfolio. We have stated an intention to exit deepwater exploration, as well as pursue other non-core dispositions. However, we are not willing to divest properties unless we achieve value.
We believe we are taking prudent actions across the business to prepare for uncertain prices and greater volatility. We have exercised significant capital flexibility, lowered our operating cost structure, reduced our dividend, and continued to high-grade our asset base. These actions, in combination with our strong execution of the business, will allow us to manage through this current period of low commodity prices and to deliver strong performance when prices recover.
Business Environment
In the first half of 2014, strong crude oil prices were supported by geopolitical tensions impacting supplies, as well as global oil demand growth. This was followed by an abrupt decline in prices beginning in the third quarter of 2014, as surging production growth from U.S. tight oil and the decision by the Organization of Petroleum Exporting Countries (OPEC) to target market share outweighed fears of supply disruptions. These developments, combined with lower forecasts for global oil demand growth, caused crude oil prices to plummet to near five-year lows at the end of 2014. As global inventories grew due to the ensuing supply surplus, prices continued even lower, and reached a ten-year quarterly low of $33.89 per barrel for Brent crude oil in the first quarter of 2016.
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 the related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC or other producers, environmental laws, tax regulations, governmental policies and weather-related changes in demand. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in
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technology responsible for the rapid growth of tight oil production, successful exploration, and rising production from the Canadian oil sands. Our strategy is to sustainably lower our cost structure and maintain a strong balance sheet while utilizing a diverse and low-cost portfolio that will provide the financial flexibility to withstand challenging business cycles.
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 U.S. Henry Hub (HH) natural gas:
Brent crude oil prices averaged $33.89 per barrel in the first quarter of 2016, a decrease of 37 percent compared with $53.97 per barrel in the first quarter of 2015. Industry crude prices for WTI averaged $33.27 per barrel in the first quarter of 2016, a decrease of 31 percent compared with $48.56 per barrel in the first quarter of 2015. Crude oil prices have remained under pressure in the first quarter of 2016 as global production continued to exceed global demand, as evidenced by a large observed inventory increase.
Henry Hub natural gas prices averaged $2.09 per million British thermal units (MMBTU) in the first quarter of 2016, a decrease of 30 percent compared with $2.99 per MMBTU in the first quarter of 2015. Natural gas prices remained under pressure with strong production levels and a warmer-than-expected winter reducing demand below expectations. U.S. underground gas storage inventories have been at or above the top of the five-year range over the past few months.
Our realized bitumen price was $1.74 per barrel in the first quarter of 2016, a decrease of 90 percent compared with the first quarter of 2015, primarily due to the significant decline in the Western Canada Select benchmark as a result of falling WTI and Brent prices.
Our total average realized price was $22.94 per barrel of oil equivalent (BOE) in the first quarter of 2016, a decrease of 38 percent compared with $36.92 per BOE in the first quarter of 2015, reflecting lower average realized prices for crude oil, natural gas, bitumen and natural gas liquids.
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Key Operating and Financial Summary
Significant items during the first quarter of 2016 included the following:
Achieved first-quarter production of 1,578 MBOED.
Reduced 2016 capital expenditures guidance from $6.4 billion to $5.7 billion.
Raised $4.6 billion of low-cost debt and ended the quarter with $5.2 billion of cash and short-term investments.
Loaded 11 cargoes from APLNG Train 1 in Australia; on track for first cargo from Train 2 in the fourth quarter of 2016.
Continue to progress toward first production at Foster Creek Phase G and Christina Lake Phase F in Canada and Alder in Europe in 2016.
Outlook
Capital and Production Guidance
We have reduced our 2016 capital expenditures guidance from $6.4 billion to $5.7 billion, primarily driven by reduced deepwater exploration activity, deferrals and lower costs across the portfolio.
We expect to meet our previously stated full-year 2016 production guidance of approximately 1,525 MBOED, in line with 2015 production adjusted for 64 MBOED for the full-year impact of 2015 dispositions. Second-quarter 2016 production guidance is 1,500 to 1,540 MBOED, which reflects significant planned turnaround activity during the quarter.
Marketing Activities
In line with our objective to continuously optimize our portfolio, we are currently marketing certain non-core assets. We expect to generate up to $1 billion in proceeds in 2016 from asset sales.
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RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2016, is based on a comparison with the corresponding period of 2015.
Consolidated Results
A summary of the Company’s net income (loss) attributable to ConocoPhillips by business segment follows:
Net income (loss) attributable to ConocoPhillips
Earnings for ConocoPhillips decreased $1,741 million in the first quarter of 2016. The decrease primarily resulted from lower commodity prices.
In addition, earnings were negatively impacted by:
The absence of a $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in the first quarter of 2015.
Higher depreciation, depletion and amortization (DD&A) expense from commodity price-related reserve revisions.
Increased property impairments.
These items were partially offset by:
Lower operating expenses.
Lower production and property taxes.
See the “Segment Results” section for additional information.
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Income Statement Analysis
Sales and other operating revenues decreased 34 percent in the first quarter of 2016, mainly as a result of lower prices across all commodities. Additionally, sales and other operating revenues were decreased due to lower natural gas liquid (NGL) and natural gas sales volumes.
Equity in earnings (losses) of affiliatesdecreased by $354 million in the first quarter of 2016, primarily as a result of lower earnings from the FCCL Partnership, Qatar Liquefied Gas Company Limited (3) (QG3) and Australia Pacific LNG Pty Ltd (APLNG) given reduced commodity prices, as well as tax-related foreign exchange impacts and increased DD&A expense, both in APLNG. The decrease in earnings was partly offset by lower production taxes at QG3.
Purchased commodities decreased 31 percent in the first quarter of 2016, largely as a result of lower natural gas prices.
Production and operating expenses decreased 25 percent in the first quarter of 2016, primarily as a result of lower operating expense activity levels, reduced headcount, dispositions of non-core assets and favorable foreign currency impacts.
Impairments increased by $120 million in the first quarter of 2016. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.
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Summary Operating Statistics
Average Net Production
Crude oil (MBD)*
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)**
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (per barrel)***
Natural gas (per thousand cubic feet)
Exploration Expenses
General administrative, geological and geophysical, and lease rentals
Leasehold impairment
Dry holes
*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.
***2015 has been restated to conform to current period presentation.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2016, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.
Total production from operations decreased 2 percent in the first quarter of 2016. The decrease in total average production primarily resulted from normal decline and the loss of 70 MBOED attributable to the 2015 dispositions of several non-core assets in the Lower 48 and western Canada, as well as the sale of our interest in the Polar Lights Company. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Greater Britannia projects in the U.K.; the Western North Slope in Alaska; and the Greater Ekofisk Area in Norway. Improved well performance in the Lower 48, Norway, Canada and China, as well as improved recoveries from production sharing contracts in Asia Pacific and Middle East also partly offset the decrease in production. In the first quarter of 2016, we achieved production of 1,578 MBOED. Adjusted for downtime and dispositions of 66 MBOED, our production increased by 34 MBOED, or 2 percent, compared with the first quarter of 2015.
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Segment Results
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)
Crude oil (MBD)
Natural gas (MMCFD)
Crude oil (dollars per barrel)
Natural gas (dollars per thousand cubic feet)
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of March 31, 2016, Alaska contributed 20 percent of our worldwide liquids production and 1 percent of our worldwide natural gas production.
Earnings from Alaska decreased $147 million in the first quarter of 2016. The decrease in earnings was primarily due to lower crude oil prices. Earnings were further decreased due to a $43 million after-tax increase in DD&A expense from commodity price-related reserve revisions in 2015, capital additions and increased production volumes. The earnings reduction was partly offset by higher crude oil sales volumes, lower property taxes mainly due to a litigation settlement in the first quarter of 2016 and reduced production and operating expenses.
Average production increased 3 percent in the first quarter of 2016 compared with the same period in 2015, primarily due to new production from the Alpine CD5 drill site and lower planned downtime activity, partly offset by normal field decline.
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Net Loss Attributable to ConocoPhillips (millions of dollars)
Natural gas liquids (dollars per barrel)
As of March 31, 2016, the Lower 48 contributed 31 percent of our worldwide liquids production and 31 percent of our worldwide natural gas production. The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico.
Lower 48 reported a loss of $820 million in the first quarter of 2016, a $415 million earnings decrease compared with the same period of 2015, primarily due to lower commodity prices. Earnings were further decreased due to a $71 million after-tax dry hole charge and a $62 million associated lease impairment related to the Melmar prospect in deepwater Gulf of Mexico; the $34 million after-tax expense for rig pre-commissioning costs in deepwater Gulf of Mexico in line with our 2015 decision to exit deepwater exploration; higher DD&A from commodity price-related reserve adjustments; a $47 million after-tax charge for the impairment of certain Gulf of Mexico leases after completion of an initial marketing effort; and reduced production. These decreases were partly offset by lower operating costs from reduced activity and general and administrative spend, as well as the absence of a $61 million after-tax dry hole charge in 2015 for the Harrier well in the Gulf of Mexico.
In the first quarter of 2016, our average realized crude oil price of $27.04 per barrel was 19 percent less than WTI of $33.27 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 9 percent in the first quarter of 2016, while average crude oil production increased 2 percent over the same period. The decrease was mainly attributable to field decline and the disposition of non-core properties in East Texas and North Louisiana, as well as South Texas. The reduction was partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin.
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Consolidated operations
Equity affiliates
Total bitumen
Bitumen (dollars per barrel)
Consolidated operations*
Total bitumen*
*2015 has been restated to conform to current period presentation.
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, 2016, Canada contributed 21 percent of our worldwide liquids production and 15 percent of our worldwide natural gas production.
Canada operations reported a loss of $294 million in the first quarter of 2016, a $136 million decrease compared with the same period of 2015, primarily due to lower bitumen and natural gas prices. The decrease was partly offset by favorable foreign currency impacts and lower operating costs resulting from cost savings and assets disposed in western Canada in 2015.
Total average production decreased 8 percent in the first quarter of 2016, while bitumen production increased 6 percent over the same period. The decrease in total production was mainly attributable to the disposition of non-core assets in western Canada and normal decline. The production decrease was partly offset by strong well performance in western Canada, as well as new production from Surmont 2.
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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, as well as in Libya. As of March 31, 2016, our Europe and North Africa operations contributed 14 percent of our worldwide liquids production and 13 percent of our worldwide natural gas production.
Earnings for Europe and North Africa operations decreased $687 million in the first quarter of 2016, primarily due to the absence of a $555 million net deferred tax benefit as a result of a change in the U.K. tax rate, effective at the beginning of 2015, lower crude oil and natural gas prices and $60 million in after-tax proved property impairments in the United Kingdom. The decrease in earnings was partly offset by lower dry hole costs in the United Kingdom, as well as lower general and administrative and maintenance expenses.
Average production increased 3 percent in the first quarter of 2016, compared to the same period in 2015. The increase was mostly due to new production from the Greater Britannia Area and the Greater Ekofisk Area, as well as improved well performance in Norway and lower unplanned downtime. The production increase was partly offset by normal field decline. Libya production remains largely shut in, as the Es Sider crude oil export terminal closure continued throughout the first quarter of 2016. Near-term operating and drilling activity remains uncertain as a result of the ongoing civil unrest.
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Total crude oil
Total natural gas liquids
Total natural gas
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, 2016, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 40 percent of our worldwide natural gas production.
Earnings for Asia Pacific and Middle East operations decreased by $400 million in the first quarter of 2016. The decrease in earnings was mainly due to lower prices across all commodities, as well as tax-related foreign exchange impacts at APLNG. The earnings decrease was partly offset by lower production taxes; reduced feedstock cost at Darwin LNG; and lower maintenance costs, general and administrative spend, and transportation expenses, across the segment.
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Average production increased 10 percent in the first quarter of 2016, compared with the same period of 2015. The production increase was mainly attributable to new production from the ramp-up of APLNG in Australia, improved drilling and well performance in China and at Gumusut, in Malaysia and increased recoveries from production sharing contracts in Indonesia and the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. Production increases were partially offset by normal field decline across the segment and a planned turnaround at QG3.
The Other International segment consists of exploration activities in Senegal, Colombia and Angola. As of March 31, 2016, Other International did not contribute to our worldwide liquids production due to the sale of our 50 percent interest in the Polar Lights Company in the fourth quarter of 2015.
Other International operations reported a loss of $24 million in the three-month period of 2016, compared with a loss of $92 million in the same period of 2015. The improvement was primarily due to the absence of the $81 million after-tax dry hole expense for the Omosi-1 well in 2015 and lower general and administrative spend, partially offset by higher rig subsidy costs in Angola.
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Net interest
Corporate general and administrative expenses
Technology
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest increased by $67 million in the first quarter of 2016, compared with the same period in 2015. Net interest increased primarily due to lower capitalized interest on projects and increased debt.
Corporate general and administrative expenses increased $64 million in the first quarter of 2016, compared with the same period of 2015, mainly due to increased pension settlement expense.
Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on unconventional reservoirs, heavy oil and oil sands, LNG, and subsurface, with an underlying commitment to environmental responsibility. Earnings from Technology improved $37 million in the first quarter of 2016, compared with the same period of 2015. The increase in earnings primarily resulted from higher licensing revenues.
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 were reduced by $70 million in the first quarter of 2016, compared to the same period of 2015 primarily due to favorable foreign currency impacts and the absence of $21 million in after-tax restructuring expenses incurred in 2015.
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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Total debt
Total equity
Percent of total debt to capital*
Percent of floating-rate debt to total debt
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is a source of funding. During the first three months of 2016, we issued $4,594 million of new debt consisting of a three-year term loan and fixed rate notes. The primary uses of our available cash were $1,821 million to support our ongoing capital expenditures and investments program and $313 million to pay dividends. During the first three months of 2016, cash and cash equivalents increased by $2,498 million to $4,866 million.
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. 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 $421 million for the first three months of 2016, compared with $2,068 million for the corresponding period of 2015, an 80 percent decrease. The decrease was primarily due to lower prices across all commodities and the absence of the $556 million tax refund received in 2015 from the Internal Revenue Service for 2014 overpaid taxes.
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. In the event we undertake any 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 2016 were $135 million, compared with $173 million for the corresponding period of 2015. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling non-core assets. For additional information regarding proceeds from asset sales, see the Outlook section within Management’s Discussion and Analysis.
Commercial Paper and Credit Facilities
On March 28, 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 to $6.75 billion. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.1 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $900 million commercial paper program, which is used to fund commitments relating to QG3. At both March 31, 2016 and December 31, 2015, we had no direct borrowings or letters of credit issued under the revolving credit facility. Under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $750 million of commercial paper was outstanding at March 31, 2016, compared with $803 million at December 31, 2015. In April 2016, we repaid an additional $640 million of the outstanding commercial paper and expect the remaining commercial paper to be repaid in the second quarter of 2016. Since we had $750 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at March 31, 2016.
Due to the recent significant decline in commodity prices and the expectation these prices could remain depressed in the near future, the major ratings agencies have conducted a review of the oil and gas industry. As a result of this review, our credit ratings, along with several other companies in the oil and gas industry, were downgraded. In the first quarter of 2016, Moody’s Investors Service downgraded our senior long-term debt ratings to “Baa2” from “A2,” with a negative outlook and our short-term commercial paper ratings to “Prime-2” from “Prime-1” and Fitch downgraded our long-term debt ratings to “A-” from “A” with a negative outlook and our short-term commercial paper ratings to “F2” from “F1.”On April 29, 2016, Standard and Poor’s downgraded our senior long-term debt ratings to “A-” from “A,” with a negative outlook and our short-term commercial paper ratings to “A-2” from “A-1.” We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a further downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.
Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2016 and December 31, 2015, we had direct bank letters of credit of $339 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of further credit ratings downgrades, we may be required to post additional letters of credit.
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Shelf Registration
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.
For information about guarantees, see Note 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures” section.
Our debt balance at March 31, 2016, was $29.5 billion, an increase of $4.6 billion from the balance at December 31, 2015, primarily as a result of obtaining a $1.6 billion three-year term loan and the issuance of $3.0 billion in new fixed rate notes, both in March 2016. Our short-term debt balance at March 31, 2016, increased $652 million compared with December 31, 2015, primarily as a result of the timing of scheduled maturities. For more information, see Note 9—Debt, in the Notes to Consolidated Financial Statements.
In February 2016, we announced a reduction in the quarterly dividend to $0.25 per share, compared with the previous quarterly dividend of $0.74 per share. We believe this effort will contribute to our balance sheet strength and provide financial flexibility through the current downturn. The dividend was paid March 1, 2016, to stockholders of record at the close of business on February 16, 2016.
Capital Expenditures
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During the first three months of 2016, 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.
Major project expenditures associated with the APLNG joint venture in Australia.
Continued oil sands development, ongoing liquids-rich plays in Canada, and exploration activities in Nova Scotia.
Alaska activities related to development in the Greater Kuparuk Area, Western North Slope and the Greater Prudhoe Area, as well as exploration activities in the National Petroleum Reserve-Alaska.
In Europe, development activities in the Greater Ekofisk, Aasta Hansteen, Clair Ridge and Greater Britannia areas.
Exploration and appraisal drilling in deepwater Gulf of Mexico.
Continued development in Malaysia, Indonesia and China.
Exploration and appraisal drilling activities in Senegal.
In April 2016, we further reduced our 2016 capital expenditures guidance from $6.4 billion to $5.7 billion, primarily driven by reduced deepwater exploration activity, deferrals, and lower costs across the portfolio.
Contingencies
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Legal 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.
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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 62–64 of our 2015 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 wastes attributable to our past operations. As of March 31, 2016, there were 14 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.
At March 31, 2016, our balance sheet included a total environmental accrual of $263 million, compared with $258 million at December 31, 2015, 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 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-based claims for damages, and may result in longer agency review time for development projects.
For other examples of legislation or precursors for possible regulation and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 64–66 of our 2015 Annual Report on Form 10-K.
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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including, but not limited to, the following:
Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, including a prolonged decline in these prices relative to historical or future expected levels.
The impact of recent, significant declines in prices for crude oil, bitumen, natural gas, LNG and natural gas liquids, which may result in recognition of impairment costs on our long-lived assets, leaseholds and nonconsolidated equity investments.
Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.
Inability to maintain reserves replacement rates consistent with prior periods, whether as a result of the recent, significant declines in commodity prices or otherwise.
Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
Unexpected changes in costs or technical requirements for constructing, modifying or operating exploration and production facilities.
Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal.
Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas, LNG and natural gas liquids.
Inability to timely obtain or maintain permits, including those necessary for drilling and/or development, construction of LNG terminals or regasification facilities; comply with government regulations; or make capital expenditures required to maintain compliance.
Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production and LNG development.
Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism, cyber attacks or infrastructure constraints or disruptions.
International monetary conditions and exchange controls, and changes in foreign currency exchange rates.
Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations, use of competing energy sources or the development of alternative energy sources.
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Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
Liability resulting from litigation.
General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and natural gas liquids pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.
Volatility in the commodity futures markets.
Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.
Competition in the oil and gas exploration and production industry.
Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.
Delays in, or our inability to, execute asset dispositions.
Inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.
The operation and financing of our joint ventures.
The ability of our customers and other contractual counterparties to satisfy their obligations to us.
Our inability to realize anticipated cost savings and expenditure reductions.
The factors generally described in Item 1A—Risk Factors in our 2015 Annual Report on Form 10-K and additional risks described in our other filings with the SEC.
Information about market risks for the three months ended March 31, 2016, does not differ materially from that discussed under Item 7A in our 2015 Annual Report on Form 10-K.
We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of March 31, 2016, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, Commercial and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance, Commercial and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of March 31, 2016.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
There have been no material changes from the risk factors disclosed in Item 1A of our 2015 Annual Report on Form 10-K.
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Item 6. EXHIBITS
* Filed herewith.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
/s/ Glenda M. Schwarz
Glenda M. Schwarz
Vice President and Controller
(Chief Accounting and Duly Authorized Officer)
May 3, 2016
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