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Note 1. Organization and nature of operations
Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development, exploration and production of oil and natural gas properties primarily located in the Permian Basin of southeast New Mexico and west Texas.
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Note 2. Summary of significant accounting policies
Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. The consolidated financial statements also include the accounts of a variable interest entity (“VIE”) where the Company is the primary beneficiary of the arrangements. See Note 4 for additional information regarding the circumstances surrounding the VIE. All material intercompany balances and transactions have been eliminated.
Reclassifications. Certain prior period amounts have been reclassified to conform to the 2017 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.
Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary exchanges, fair value of derivative financial instruments and income taxes.
Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2016 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.
Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2016, the majority of the Company’s cash was invested in stable value government money market funds.
Equity method investments. At December 31, 2016, the Company owned a 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that operated a crude oil gathering and transportation system in the Northern Delaware Basin. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. See Note 4 for additional information regarding the disposition of ACC.
The Company accounted for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC was approximately $129 million at December 31, 2016, and was included in other assets in the Company’s consolidated balance sheet. Gains and losses incurred from the Company’s equity investment in ACC were recorded in other income (expense) in its consolidated statements of operations.
The Company owns a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Southern Delaware Basin. The Company accounts for its investment in Oryx under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in Oryx was approximately $47 million and $42 million at September 30, 2017 and December 31, 2016, respectively, and is included in other assets in the Company’s consolidated balance sheets. Gains and losses incurred from the Company’s equity investment in Oryx are recorded in other income (expense) in its consolidated statements of operations.
Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.
General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. The Company earned reimbursements of approximately $4 million for each of the three months ended September 30, 2017 and 2016 and approximately $12 million for each of the nine months ended September 30, 2017 and 2016.
Recently adopted accounting pronouncements. The Company adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period consolidated financial statements. The Company elected to account for forfeitures of share-based payments as they occur. At December 31, 2016, the Company had not recorded compensation expense of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million. The Company recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption, the Company recorded a cumulative-effect adjustment, which decreased retained earnings by less than $1 million, increased additional paid-in capital by approximately $8 million, and decreased net deferred income taxes by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating activities on the consolidated statements of cash flows and will prospectively record those excess tax benefits and deficiencies as discrete items in the income tax provision in the consolidated statements of operations. Under the new standard, for the nine months ended September 30, 2017, the Company recorded excess tax benefits of approximately $6 million as offsets to the Company’s income tax provision. Also under the new standard, for the three and nine months ended September 30, 2017, the Company recorded forfeitures of share-based payments of approximately $1 million and $7 million, respectively.
New accounting pronouncements issued but not yet adopted. In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.
In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized with an adjustment to retained earnings on January 1, 2018. The Company has substantially completed its internal evaluation of the adoption of this standard, which included a review of all revenue-related contracts with customers and the application of the new revenue recognition model against those contracts. The Company is also updating its revenue recognition policy to conform to the new standard. The Company also expects to expand its revenue recognition related disclosure. Including those changes previously discussed, the Company does not expect this new guidance will have a material impact on its consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company is currently in the process of reviewing all contracts that could be applicable to this new guidance. The Company believes this new guidance will have a moderate impact to its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under currently applicable guidance.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. The Company is evaluating the impact this new guidance will have on its consolidated financial statements.
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Note 3. Exploratory well costs
The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 15 for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.
The following table reflects the Company’s net capitalized exploratory well activity during the nine months ended September 30, 2017:
Nine Months Ended | |||||||
(in millions) | September 30, 2017 | ||||||
Beginning capitalized exploratory well costs | $ | 151 | |||||
Additions to exploratory well costs pending the determination of proved reserves | 255 | ||||||
Reclassifications due to determination of proved reserves | (136) | ||||||
Ending capitalized exploratory well costs | $ | 270 | |||||
The following table provides an aging at September 30, 2017 and December 31, 2016 of capitalized exploratory well costs based on the date drilling was completed:
September 30, | December 31, | ||||||
(in millions, except number of projects) | 2017 | 2016 | |||||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 266 | $ | 141 | |||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | 4 | 10 | |||||
Total capitalized exploratory well costs | $ | 270 | $ | 151 | |||
Number of projects with exploratory well costs that have been capitalized for a period greater | |||||||
than one year | 4 | 8 | |||||
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Note 4. Acquisitions and divestitures
Midland Basin acquisition. In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash. The acquisition is subject to customary post-closing adjustments.
Concurrent with the acquisition, the Company entered into a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended (the “Code”). In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operates the properties pursuant to a management agreement with the VIE. At September 30, 2017, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance. The assets currently held by the VIE attributable to the acquisition will be conveyed to the Company or one of its subsidiaries, and the VIE structure will terminate, upon the earlier of (i) the completion of the Reverse 1031 Exchange or (ii) the expiration of the time allowed by the treasury regulations and published Internal Revenue Service guidance to complete the Reverse 1031 Exchange, which is 180 days from commencement. At September 30, 2017, the VIE’s total assets and liabilities included in the Company’s consolidated balance sheet were approximately $607 million and $605 million, respectively.
Northern Delaware Basin acquisition. In April 2017, the Company closed on the remainder of its acquisition in the Northern Delaware Basin. As consideration for the entire acquisition, the Company paid approximately $160 million in cash, of which $43 million was held in escrow at December 31, 2016, and issued to the seller approximately 2.2 million shares of its common stock with an approximate value of $291 million.
ACC divestiture. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. The Company and its joint venture partner entered into separate agreements to sell 100 percent of their respective ownership interests in ACC. After adjustments for debt and working capital, the Company received cash proceeds from the sale of approximately $801 million. After direct transaction costs, the Company recorded a pre-tax gain on disposition of assets of approximately $655 million. The Company’s net investment in ACC at the time of closing was approximately $129 million.
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Note 5. Stock incentive plan
The Company’s 2015 Stock Incentive Plan provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. The restricted stock-based compensation awards generally vest over a period ranging from one to eight years.
A summary of the Company’s Stock Incentive Plan activity for the nine months ended September 30, 2017 is presented below:
Restricted | Stock | Performance | |||||||||
Stock Shares | Options | Units | |||||||||
Outstanding at December 31, 2016 | 1,157,270 | 20,000 | 331,526 | ||||||||
Awards granted (a) | 445,384 | - | 108,398 | ||||||||
Options exercised | - | (20,000) | - | ||||||||
Awards cancelled / forfeited | (82,200) | - | (43,333) | ||||||||
Lapse of restrictions | (389,965) | - | - | ||||||||
Outstanding at September 30, 2017 | 1,130,489 | - | 396,591 | ||||||||
(a) Weighted average grant date fair value per share/unit | $ | 121.77 | $ | - | $ | 183.48 | |||||
The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at September 30, 2017:
(in millions) | ||||
Remaining 2017 | $ | 17 | ||
2018 | 47 | |||
2019 | 25 | |||
Thereafter | 8 | |||
Total | $ | 97 | ||
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Note 6. Disclosures about fair value measurements
The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.
Level 3: Prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Financial Assets and Liabilities Measured at Fair Value
The following table presents the carrying amounts and fair values of the Company’s financial instruments at September 30, 2017 and December 31, 2016:
September 30, 2017 | December 31, 2016 | |||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||
(in millions) | Value | Value | Value | Value | ||||||||||
Assets: | ||||||||||||||
Derivative instruments | $ | 32 | $ | 32 | $ | 4 | $ | 4 | ||||||
Liabilities: | ||||||||||||||
Derivative instruments | $ | 43 | $ | 43 | $ | 178 | $ | 178 | ||||||
Credit facility | $ | 368 | $ | 368 | $ | - | $ | - | ||||||
$600 million 5.5% senior notes due 2022 (a) | $ | - | $ | - | $ | 594 | $ | 620 | ||||||
$1,550 million 5.5% senior notes due 2023 (a) | $ | - | $ | - | $ | 1,555 | $ | 1,621 | ||||||
$600 million 4.375% senior notes due 2025 (a) | $ | 593 | $ | 632 | $ | 592 | $ | 599 | ||||||
$1,000 million 3.75% senior notes due 2027 (a) | $ | 988 | $ | 1,006 | $ | - | $ | - | ||||||
$800 million 4.875% senior notes due 2047 (a) | $ | 789 | $ | 834 | $ | - | $ | - | ||||||
(a) | The carrying value includes associated deferred loan costs and any premium (discount). |
Credit facility. The carrying amount of the Company’s credit facility approximates its fair value, as the applicable interest rates are variable and reflective of market rates.
Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.
Other financial assets and liabilities. The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2017 and December 31, 2016. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.
September 30, 2017 | ||||||||||||||||||||||
Fair Value Measurements Using | Net | |||||||||||||||||||||
Quoted Prices | Gross | Fair Value | ||||||||||||||||||||
in Active | Significant | Amounts | Presented | |||||||||||||||||||
Markets for | Other | Significant | Offset in the | in the | ||||||||||||||||||
Identical | Observable | Unobservable | Consolidated | Consolidated | ||||||||||||||||||
Assets | Inputs | Inputs | Total | Balance | Balance | |||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Fair Value | Sheet | Sheet | ||||||||||||||||
Assets: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | $ | - | $ | 35 | $ | - | $ | 35 | $ | (31) | $ | 4 | ||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | 44 | - | 44 | (16) | 28 | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | - | (68) | - | (68) | 31 | (37) | ||||||||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | (22) | - | (22) | 16 | (6) | ||||||||||||||||
Net derivative instruments | $ | - | $ | (11) | $ | - | $ | (11) | $ | - | $ | (11) | ||||||||||
December 31, 2016 | ||||||||||||||||||||||
Fair Value Measurements Using | Net | |||||||||||||||||||||
Quoted Prices | Gross | Fair Value | ||||||||||||||||||||
in Active | Significant | Amounts | Presented | |||||||||||||||||||
Markets for | Other | Significant | Offset in the | in the | ||||||||||||||||||
Identical | Observable | Unobservable | Consolidated | Consolidated | ||||||||||||||||||
Assets | Inputs | Inputs | Total | Balance | Balance | |||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Fair Value | Sheet | Sheet | ||||||||||||||||
Assets: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | $ | - | $ | 59 | $ | - | $ | 59 | $ | (55) | $ | 4 | ||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | - | - | - | - | - | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | - | (137) | - | (137) | 55 | (82) | ||||||||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | (96) | - | (96) | - | (96) | ||||||||||||||||
Net derivative instruments | $ | - | $ | (174) | $ | - | $ | (174) | $ | - | $ | (174) | ||||||||||
Concentrations of credit risk. At September 30, 2017, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.
The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 7 for additional information regarding the Company’s derivative activities and counterparties.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Impairments of long-lived assets – The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.
The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing market rates of income and expenses from integrated assets. At September 30, 2017, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2017 price of $52.29 per barrel of oil decreasing to a 2021 price of $50.77 per barrel of oil partially recovering to a 2024 price of $52.01 per barrel of oil. Similarly, natural gas prices ranged from a 2017 price of $3.14 per Mcf of natural gas decreasing to a 2020 price of $2.85 per Mcf of natural gas partially recovering to a 2024 price of $2.88 per Mcf of natural gas. Commodity prices for this purpose were held flat after 2024.
The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) a discount rate. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. These are classified as Level 3 fair value assumptions.
During the three months ended March 31, 2016, NYMEX strip prices declined as compared to December 31, 2015, and as a result the carrying amount of the Company’s Yeso field of approximately $3.4 billion exceeded the expected undiscounted future net cash flows resulting in a non-cash charge against earnings of approximately $1.5 billion. The non-cash charge represented the amount by which the carrying amount exceeded the estimated fair value of the assets.
The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated period:
Estimated | |||||||||
Carrying | Fair Value | Impairment | |||||||
(in millions) | Amount | (Level 3) | Expense | ||||||
March 2016 | $ | 3,438 | $ | 1,913 | $ | 1,525 | |||
It is reasonably possible that the estimate of undiscounted future net cash flows of the Company’s long-lived assets may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity prices including differentials, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.
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Note 7. Derivative financial instruments
The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also enters into fixed-price forward physical power purchase contracts to manage the volatility of the price of power needed for ongoing operations. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical contracts are not expected to be net cash settled, the Company has elected normal purchase or normal sale treatment and are thus recorded at cost.
The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur.
The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three and nine months ended September 30, 2017 and 2016:
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Gain (loss) on derivatives: | ||||||||||||||
Oil derivatives | $ | (205) | $ | 36 | $ | 260 | $ | (173) | ||||||
Natural gas derivatives | (1) | 5 | 29 | (3) | ||||||||||
Total | $ | (206) | $ | 41 | $ | 289 | $ | (176) | ||||||
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2017 and 2016: | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Net cash receipts from (payments on) derivatives: | ||||||||||||||
Oil derivatives | $ | 28 | $ | 154 | $ | 129 | $ | 566 | ||||||
Natural gas derivatives | 2 | 1 | (3) | 16 | ||||||||||
Total | $ | 30 | $ | 155 | $ | 126 | $ | 582 | ||||||
Commodity derivative contracts at September 30, 2017. The following table sets forth the Company’s outstanding derivative contracts at September 30, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 2017 are expected to settle by December 31, 2019.
First | Second | Third | Fourth | ||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||
Oil Price Swaps: (a) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 9,370,080 | 9,370,080 | |||||||||||
Price per Bbl | $ | 51.33 | $ | 51.33 | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 8,180,629 | 7,546,170 | 7,064,318 | 6,676,007 | 29,467,124 | ||||||||
Price per Bbl | $ | 51.54 | $ | 51.45 | $ | 51.36 | $ | 51.26 | $ | 51.41 | |||
2019: | |||||||||||||
Volume (Bbl) | 5,314,000 | 5,090,000 | 4,897,000 | 4,721,000 | 20,022,000 | ||||||||
Price per Bbl | $ | 52.54 | $ | 52.52 | $ | 52.54 | $ | 52.55 | $ | 52.54 | |||
Oil Basis Swaps: (b) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 8,508,000 | 8,508,000 | |||||||||||
Price per Bbl | $ | (0.74) | $ | (0.74) | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 7,936,000 | 7,521,000 | 6,961,000 | 6,684,000 | 29,102,000 | ||||||||
Price per Bbl | $ | (1.02) | $ | (1.01) | $ | (1.01) | $ | (1.01) | $ | (1.01) | |||
2019: | |||||||||||||
Volume (Bbl) | 4,581,000 | 4,428,000 | 4,262,000 | 4,139,000 | 17,410,000 | ||||||||
Price per Bbl | $ | (1.17) | $ | (1.17) | $ | (1.18) | $ | (1.18) | $ | (1.17) | |||
Natural Gas Price Swaps: (c) | |||||||||||||
2017: | |||||||||||||
Volume (MMBtu) | 14,673,000 | 14,673,000 | |||||||||||
Price per MMBtu | $ | 3.10 | $ | 3.10 | |||||||||
2018: | |||||||||||||
Volume (MMBtu) | 11,156,000 | 10,641,000 | 10,219,000 | 9,904,000 | 41,920,000 | ||||||||
Price per MMBtu | $ | 3.06 | $ | 3.05 | $ | 3.05 | $ | 3.04 | $ | 3.05 | |||
2019: | |||||||||||||
Volume (MMBtu) | 2,791,533 | 2,681,387 | 2,578,537 | 2,489,535 | 10,540,992 | ||||||||
Price per MMBtu | $ | 2.86 | $ | 2.85 | $ | 2.85 | $ | 2.85 | $ | 2.85 | |||
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. | |||||||||||||
(b) The basis differential price is between Midland – WTI and Cushing – WTI. | |||||||||||||
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. | |||||||||||||
Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company. In September 2017, the Company elected to enter into an “Investment Grade Period” under the Credit Facility, as defined below, which had the effect of releasing all collateral formerly securing the Credit Facility. Additionally, as a result of the Company’s Investment Grade Period election along with amendments to certain ISDA Agreements with the Company’s derivative counterparties, the Company’s derivatives are no longer secured. See Note 8 for additional information regarding the Credit Facility.
|
Note 8. Debt
The Company’s debt consisted of the following at September 30, 2017 and December 31, 2016:
September 30, | December 31, | |||||||
(in millions) | 2017 | 2016 | ||||||
Credit facility | $ | 368 | $ | - | ||||
5.5% unsecured senior notes due 2022 | - | 600 | ||||||
5.5% unsecured senior notes due 2023 | - | 1,550 | ||||||
4.375% unsecured senior notes due 2025 | 600 | 600 | ||||||
3.75% unsecured senior notes due 2027 | 1,000 | - | ||||||
4.875% unsecured senior notes due 2047 | 800 | - | ||||||
Unamortized original issue premium (discount), net | (6) | 22 | ||||||
Senior notes issuance costs, net | (24) | (31) | ||||||
Less: current portion | - | - | ||||||
Total long-term debt | $ | 2,738 | $ | 2,741 | ||||
Credit facility. The Company’s credit facility, as amended and restated (the “Credit Facility”), has a maturity date of May 9, 2022. At September 30, 2017, the Company’s commitments from its bank group were $2.0 billion.
In April 2017, the Company amended the Credit Facility to extend the maturity date, increase the borrowing base and decrease unused lender commitments. The amendment also lowered the corporate ratings floor sufficient to automatically terminate an Investment Grade Period under the Credit Facility from (i) “Ba1” to “Ba2” for Moody’s Investors Service, Inc. (“Moody’s”) and (ii) “BB+” to “BB” for S&P Global Ratings (“S&P”).
The Company recorded a loss on extinguishment of debt of approximately $1 million during the nine months ended September 30, 2017 for the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the Credit Facility syndicate as a result of the April 2017 amendment.
In September 2017, the Company elected to enter into an Investment Grade Period under the Credit Facility, which had the effect of releasing all collateral formerly securing the Credit Facility. If the Investment Grade Period under the Credit Facility terminates (whether automatically due to a downgrade of the Company’s credit ratings below certain thresholds or by the Company’s election), the Credit Facility will once again be secured by a first lien on substantially all of the Company’s oil and natural gas properties and by a pledge of the equity interests in its subsidiaries. At September 30, 2017, certain of the Company’s 100 percent owned subsidiaries are guarantors under the Credit Facility.
During an Investment Grade Period, advances on the Credit Facility bear interest, at the Company’s option, based on (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (4.25 percent at September 30, 2017), (b) the federal funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent or (ii) LIBOR. The Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on the Company’s credit ratings from Moody’s and S&P. At the Company’s current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.
The Credit Facility contains various restrictive covenants and compliance requirements, which include:
Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note 13.
In September 2017, the Company issued $1,800 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 (the “3.75% Notes”) and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 (the “4.875% Notes” and, together with the 3.75% Notes, the “Notes”). The 3.75% Notes were issued at a price equal to 99.636 percent of par, and the 4.875% Notes were issued at a price equal to 99.749 percent of par. The Company received net proceeds of approximately $1,777 million.
Additionally, in September 2017, the Company completed a cash tender offer (the “Tender Offer”) to purchase any and all of the outstanding $600 million aggregate principal amount of its 5.5% unsecured senior notes due 2022 and the outstanding $1,550 million aggregate principal amount of its 5.5% unsecured senior notes due 2023 (collectively, the “5.5% Notes”). The Company received tenders from the holders of approximately $1,232 million in aggregate principal amount, or approximately 57.3 percent, of its outstanding 5.5% Notes in connection with the Tender Offer at a price of 102.934 percent of the unpaid principal amount plus accrued and unpaid interest to the settlement date.
In connection with the Tender Offer, the Company redeemed the remaining outstanding 5.5% Notes not purchased in the Tender Offer at a price, including the make-whole premium as determined in accordance with the indentures, of 102.75 percent of the unpaid principal amount plus accrued and unpaid interest. Additionally in September 2017, the Company completed a satisfaction and discharge of the redeemed notes, where the Company prepaid interest to October 13, 2017. The Company used the net proceeds from the offering of the Notes, together with cash on hand and borrowings under its Credit Facility, to fund the Tender Offer and the satisfaction and discharge of its obligations under the indentures of the 5.5% Notes.
As a result of these transactions, the Company recorded a loss on extinguishment of debt for the three and nine months ended September 30, 2017 as follows:
(in millions) | Tender Offer | Extinguishment | Total | ||||||||
Tender premium | $ | 36 | $ | - | $ | 36 | |||||
Make-whole premium | - | 25 | 25 | ||||||||
Prepaid interest | - | 2 | 2 | ||||||||
Unamortized original issue premium | (11) | (8) | (19) | ||||||||
Unamortized deferred loan costs | 12 | 9 | 21 | ||||||||
Total loss on extinguishment of debt | $ | 37 | $ | 28 | $ | 65 | |||||
At September 30, 2017, the Company was in compliance with the covenants under all of its debt instruments.
Principal maturities of long-term debt. Principal maturities of long-term debt outstanding at September 30, 2017 were as follows:
(in millions) | |||||
Remaining 2017 | $ | - | |||
2018 | - | ||||
2019 | - | ||||
2020 | - | ||||
2021 | - | ||||
2022 | 368 | ||||
Thereafter | 2,400 | ||||
Total | $ | 2,768 | |||
Interest expense. The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2017 and 2016:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Cash payments for interest | $ | 73 | $ | 109 | $ | 138 | $ | 215 | ||||||||
Non-cash interest | 1 | 3 | 5 | 7 | ||||||||||||
Net changes in accruals | (35) | (59) | (25) | (60) | ||||||||||||
Total interest expense | $ | 39 | $ | 53 | $ | 118 | $ | 162 | ||||||||
|
Note 9. Commitments and contingencies
Legal actions. The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.
Severance tax, royalty and joint interest audits. The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At December 31, 2016, the Company had $7 million accrued for estimated exposure that has since been satisfied. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.
Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including drilling commitments, water commitment agreements, throughput volume delivery commitments, power commitments, fixed asset commitments and maintenance commitments. The following table summarizes the Company’s commitments at September 30, 2017:
(in millions) | ||||
Remaining 2017 | $ | 10 | ||
2018 | 40 | |||
2019 | 59 | |||
2020 | 32 | |||
2021 | 31 | |||
2022 | 26 | |||
Thereafter | 88 | |||
Total | $ | 286 | ||
Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases were approximately $2 million for each of the three months ended September 30, 2017 and 2016 and approximately $7 million and $6 million for the nine months ended September 30, 2017 and 2016, respectively.
Future minimum lease commitments under non-cancellable operating leases at September 30, 2017 were as follows:
(in millions) | ||||
Remaining 2017 | $ | 2 | ||
2018 | 9 | |||
2019 | 7 | |||
2020 | 6 | |||
2021 | 4 | |||
2022 | - | |||
Thereafter | 1 | |||
Total | $ | 29 | ||
|
Note 10. Income taxes
The effective income tax rates were 36.7 percent and 37.3 percent for the three months ended September 30, 2017 and 2016, respectively, and 36.6 percent and 36.9 percent for the nine months ended September 30, 2017 and 2016, respectively. Total income tax expense for the nine months ended September 30, 2017 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax income primarily due to state income taxes and the impact of permanent differences between book and taxable income. The Company recorded a discrete income tax benefit of approximately $6 million for the nine months ended September 30, 2017 related to excess tax benefits on stock-based awards, which are recorded in the income tax provision pursuant to ASU No. 2016-09, which was adopted on January 1, 2017. Total income tax benefit for the three months ended September 30, 2017 and the three and nine months ended September 30, 2016 differed from amounts computed by applying the United States federal statutory tax rates to pre-tax loss primarily due to state income taxes, partially offset by the impact of permanent differences between book and taxable loss.
|
Note 11. Related party transactions
The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled approximately $1 million for each of the three months ended September 30, 2017 and 2016 and approximately $5 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.
|
Note 13. Subsidiary guarantors
At September 30, 2017, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.
See Note 8 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, two of the Company’s subsidiaries do not guarantee the Company’s senior notes and are included in the Company’s consolidated financial statements. One of such entities is a VIE that was formed to effectuate a tax-free exchange of assets, and the other entity is a 100 percent owned subsidiary that was recently acquired. These entities are referred to as “Subsidiary Non-Guarantors” in the tables below.
The following condensed consolidating balance sheets at September 30, 2017 and December 31, 2016, condensed consolidating statements of operations for the three and nine months ended September 30, 2017 and 2016 and condensed consolidating statements of cash flows for the nine months ended September 30, 2017 and 2016, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.
Condensed Consolidating Balance Sheet | ||||||||||||||||
September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
ASSETS | ||||||||||||||||
Accounts receivable - related parties | $ | 8,903 | $ | (653) | $ | - | $ | (8,250) | $ | - | ||||||
Other current assets | 14 | 515 | 6 | - | 535 | |||||||||||
Oil and natural gas properties, net | - | 11,968 | 619 | - | 12,587 | |||||||||||
Property and equipment, net | - | 232 | - | - | 232 | |||||||||||
Investment in subsidiaries | 2,963 | - | - | (2,963) | - | |||||||||||
Other long-term assets | 42 | 86 | - | - | 128 | |||||||||||
Total assets | $ | 11,922 | $ | 12,148 | $ | 625 | $ | (11,213) | $ | 13,482 | ||||||
LIABILITIES AND EQUITY | ||||||||||||||||
Accounts payable - related parties | $ | (653) | $ | 8,290 | $ | 613 | $ | (8,250) | $ | - | ||||||
Other current liabilities | 50 | 756 | 4 | - | 810 | |||||||||||
Long-term debt | 2,738 | - | - | - | 2,738 | |||||||||||
Other long-term liabilities | 1,156 | 141 | 6 | - | 1,303 | |||||||||||
Equity | 8,631 | 2,961 | 2 | (2,963) | 8,631 | |||||||||||
Total liabilities and equity | $ | 11,922 | $ | 12,148 | $ | 625 | $ | (11,213) | $ | 13,482 | ||||||
Condensed Consolidating Balance Sheet | |||||||||||||
December 31, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
ASSETS | |||||||||||||
Accounts receivable - related parties | $ | 8,991 | $ | (336) | $ | (8,655) | $ | - | |||||
Other current assets | 12 | 534 | - | 546 | |||||||||
Oil and natural gas properties, net | - | 11,086 | - | 11,086 | |||||||||
Property and equipment, net | - | 216 | - | 216 | |||||||||
Investment in subsidiaries | 1,989 | - | (1,989) | - | |||||||||
Other long-term assets | 11 | 260 | - | 271 | |||||||||
Total assets | $ | 11,003 | $ | 11,760 | $ | (10,644) | $ | 12,119 | |||||
LIABILITIES AND EQUITY | |||||||||||||
Accounts payable - related parties | $ | (336) | $ | 8,991 | $ | (8,655) | $ | - | |||||
Other current liabilities | 114 | 639 | - | 753 | |||||||||
Long-term debt | 2,741 | - | - | 2,741 | |||||||||
Other long-term liabilities | 861 | 141 | - | 1,002 | |||||||||
Equity | 7,623 | 1,989 | (1,989) | 7,623 | |||||||||
Total liabilities and equity | $ | 11,003 | $ | 11,760 | $ | (10,644) | $ | 12,119 | |||||
Condensed Consolidating Statement of Operations | ||||||||||||||||
Three Months Ended September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
Total operating revenues | $ | - | $ | 619 | $ | 8 | $ | - | $ | 627 | ||||||
Total operating costs and expenses | (207) | (491) | (6) | - | (704) | |||||||||||
Income (loss) from operations | (207) | 128 | 2 | - | (77) | |||||||||||
Interest expense | (39) | - | - | - | (39) | |||||||||||
Loss on extinguishment of debt | (65) | - | - | - | (65) | |||||||||||
Other, net | 132 | 2 | - | (132) | 2 | |||||||||||
Income (loss) before income | ||||||||||||||||
taxes | (179) | 130 | 2 | (132) | (179) | |||||||||||
Income tax benefit | 66 | - | - | - | 66 | |||||||||||
Net income (loss) | $ | (113) | $ | 130 | $ | 2 | $ | (132) | $ | (113) | ||||||
Condensed Consolidating Statement of Operations | |||||||||||||
Three Months Ended September 30, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
Total operating revenues | $ | - | $ | 430 | $ | - | $ | 430 | |||||
Total operating costs and expenses | 41 | (469) | - | (428) | |||||||||
Income (loss) from operations | 41 | (39) | - | 2 | |||||||||
Interest expense | (52) | (1) | - | (53) | |||||||||
Loss on extinguishment of debt | (28) | - | - | (28) | |||||||||
Other, net | (42) | (2) | 42 | (2) | |||||||||
Loss before income taxes | (81) | (42) | 42 | (81) | |||||||||
Income tax benefit | 30 | - | - | 30 | |||||||||
Net loss | $ | (51) | $ | (42) | $ | 42 | $ | (51) | |||||
Condensed Consolidating Statement of Operations | ||||||||||||||||
Nine Months Ended September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
Total operating revenues | $ | - | $ | 1,798 | $ | 8 | $ | - | $ | 1,806 | ||||||
Total operating costs and expenses | 288 | (835) | (6) | - | (553) | |||||||||||
Income from operations | 288 | 963 | 2 | - | 1,253 | |||||||||||
Interest expense | (117) | (1) | - | - | (118) | |||||||||||
Loss on extinguishment of debt | (66) | - | - | - | (66) | |||||||||||
Other, net | 982 | 18 | - | (982) | 18 | |||||||||||
Income before income taxes | 1,087 | 980 | 2 | (982) | 1,087 | |||||||||||
Income tax expense | (398) | - | - | - | (398) | |||||||||||
Net income | $ | 689 | $ | 980 | $ | 2 | $ | (982) | $ | 689 | ||||||
Condensed Consolidating Statement of Operations | |||||||||||||
Nine Months Ended September 30, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
Total operating revenues | $ | - | $ | 1,110 | $ | - | $ | 1,110 | |||||
Total operating costs and expenses | (177) | (2,853) | - | (3,030) | |||||||||
Loss from operations | (177) | (1,743) | - | (1,920) | |||||||||
Interest expense | (159) | (3) | - | (162) | |||||||||
Loss on extinguishment of debt | (28) | - | - | (28) | |||||||||
Other, net | (1,755) | (10) | 1,756 | (9) | |||||||||
Loss before income taxes | (2,119) | (1,756) | 1,756 | (2,119) | |||||||||
Income tax benefit | 782 | - | - | 782 | |||||||||
Net loss | $ | (1,337) | $ | (1,756) | $ | 1,756 | $ | (1,337) | |||||
Condensed Consolidating Statement of Cash Flows | |||||||||||||||||
Nine Months Ended September 30, 2017 | |||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | ||||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | ||||||||||||
Net cash flows provided by operating activities | $ | 99 | $ | 1,084 | $ | 2 | $ | - | $ | 1,185 | |||||||
Net cash flows used in investing activities | - | (592) | (615) | - | (1,207) | ||||||||||||
Net cash flows provided by (used in) financing | |||||||||||||||||
activities | (99) | (545) | 613 | - | (31) | ||||||||||||
Net decrease in cash and cash equivalents | - | (53) | - | - | (53) | ||||||||||||
Cash and cash equivalents at beginning of period | - | 53 | - | - | 53 | ||||||||||||
Cash and cash equivalents at end of period | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||
Nine Months Ended September 30, 2016 | ||||||||||||||
Parent | Subsidiary | Consolidating | ||||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | ||||||||||
Net cash flows provided by (used in) operating activities | $ | (694) | $ | 1,713 | $ | - | $ | 1,019 | ||||||
Net cash flows used in investing activities | - | (783) | - | (783) | ||||||||||
Net cash flows provided by financing activities | 694 | - | - | 694 | ||||||||||
Net increase in cash and cash equivalents | - | 930 | - | 930 | ||||||||||
Cash and cash equivalents at beginning of period | - | 229 | - | 229 | ||||||||||
Cash and cash equivalents at end of period | $ | - | $ | 1,159 | $ | - | $ | 1,159 | ||||||
|
Note 14. Subsequent events
New commodity derivative contracts. After September 30, 2017, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:
First | Second | Third | Fourth | ||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||
Oil Price Swaps: (a) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 846,000 | 846,000 | |||||||||||
Price per Bbl | $ | 51.29 | $ | 51.29 | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 953,000 | 600,000 | 407,000 | 296,000 | 2,256,000 | ||||||||
Price per Bbl | $ | 51.55 | $ | 51.39 | $ | 51.43 | $ | 51.28 | $ | 51.45 | |||
2019: | |||||||||||||
Volume (Bbl) | 1,035,000 | 1,046,500 | 828,000 | 828,000 | 3,737,500 | ||||||||
Price per Bbl | $ | 51.25 | $ | 51.25 | $ | 51.14 | $ | 51.14 | $ | 51.20 | |||
Oil Basis Swaps: (b) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 1,499,000 | 1,499,000 | |||||||||||
Price per Bbl | $ | (0.12) | $ | (0.12) | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 540,000 | 546,000 | 276,000 | 276,000 | 1,638,000 | ||||||||
Price per Bbl | $ | (0.21) | $ | (0.21) | $ | (0.38) | $ | (0.38) | $ | (0.27) | |||
2019: | |||||||||||||
Volume (Bbl) | 1,395,000 | 1,410,500 | 1,426,000 | 1,426,000 | 5,657,500 | ||||||||
Price per Bbl | $ | (0.68) | $ | (0.68) | $ | (0.68) | $ | (0.68) | $ | (0.68) | |||
Natural Gas Price Swaps: (c) | |||||||||||||
2017: | |||||||||||||
Volume (MMBtu) | 3,660,000 | 3,660,000 | |||||||||||
Price per MMBtu | $ | 3.02 | $ | 3.02 | |||||||||
2018: | |||||||||||||
Volume (MMBtu) | 5,400,000 | 5,460,000 | 4,600,000 | 4,600,000 | 20,060,000 | ||||||||
Price per MMBtu | $ | 3.02 | $ | 3.02 | $ | 3.01 | $ | 3.01 | $ | 3.02 | |||
2019: | |||||||||||||
Volume (MMBtu) | 1,800,000 | 1,820,000 | 1,840,000 | 1,840,000 | 7,300,000 | ||||||||
Price per MMBtu | $ | 2.86 | $ | 2.86 | $ | 2.86 | $ | 2.86 | $ | 2.86 | |||
(a) | The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price. | ||||||||||||
(b) | The basis differential price is between Midland – WTI and Cushing – WTI. | ||||||||||||
(c) | The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. | ||||||||||||
|
Note 15. Supplementary information
Capitalized costs
September 30, | December 31, | |||||||
(in millions) | 2017 | 2016 | ||||||
Oil and natural gas properties: | ||||||||
Proved | $ | 17,950 | $ | 16,620 | ||||
Unproved | 2,804 | 1,856 | ||||||
Less: accumulated depletion | (8,167) | (7,390) | ||||||
Net capitalized costs for oil and natural gas properties | $ | 12,587 | $ | 11,086 | ||||
Costs incurred for oil and natural gas producing activities
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Property acquisition costs: | ||||||||||||||
Proved | $ | 162 | $ | 1 | $ | 301 | $ | 257 | ||||||
Unproved | 472 | 14 | 865 | 172 | ||||||||||
Exploration | 252 | 177 | 725 | 513 | ||||||||||
Development | 175 | 97 | 478 | 287 | ||||||||||
Total costs incurred for oil and natural gas properties | $ | 1,061 | $ | 289 | $ | 2,369 | $ | 1,229 | ||||||
|
Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. The consolidated financial statements also include the accounts of a variable interest entity (“VIE”) where the Company is the primary beneficiary of the arrangements. See Note 4 for additional information regarding the circumstances surrounding the VIE. All material intercompany balances and transactions have been eliminated.
Reclassifications. Certain prior period amounts have been reclassified to conform to the 2017 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.
Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary exchanges, fair value of derivative financial instruments and income taxes.
Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2016 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.
Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. At December 31, 2016, the majority of the Company’s cash was invested in stable value government money market funds.
Equity method investments. At December 31, 2016, the Company owned a 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that operated a crude oil gathering and transportation system in the Northern Delaware Basin. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. See Note 4 for additional information regarding the disposition of ACC.
The Company accounted for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC was approximately $129 million at December 31, 2016, and was included in other assets in the Company’s consolidated balance sheet. Gains and losses incurred from the Company’s equity investment in ACC were recorded in other income (expense) in its consolidated statements of operations.
The Company owns a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Southern Delaware Basin. The Company accounts for its investment in Oryx under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in Oryx was approximately $47 million and $42 million at September 30, 2017 and December 31, 2016, respectively, and is included in other assets in the Company’s consolidated balance sheets. Gains and losses incurred from the Company’s equity investment in Oryx are recorded in other income (expense) in its consolidated statements of operations.
Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.
General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions of general and administrative expense. The Company earned reimbursements of approximately $4 million for each of the three months ended September 30, 2017 and 2016 and approximately $12 million for each of the nine months ended September 30, 2017 and 2016.
Recently adopted accounting pronouncements. The Company adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements to Employee Share-based Payment Accounting,” on January 1, 2017. The adoption did not have an impact on prior period consolidated financial statements. The Company elected to account for forfeitures of share-based payments as they occur. At December 31, 2016, the Company had not recorded compensation expense of approximately $8 million based on forecasted forfeitures nor the associated deferred tax benefit of approximately $3 million. The Company recognized all excess tax benefits not previously recorded, which totaled approximately $5 million at December 31, 2016. Upon adoption, the Company recorded a cumulative-effect adjustment, which decreased retained earnings by less than $1 million, increased additional paid-in capital by approximately $8 million, and decreased net deferred income taxes by approximately $8 million. The Company elected to prospectively classify excess tax benefits and deficiencies as operating activities on the consolidated statements of cash flows and will prospectively record those excess tax benefits and deficiencies as discrete items in the income tax provision in the consolidated statements of operations. Under the new standard, for the nine months ended September 30, 2017, the Company recorded excess tax benefits of approximately $6 million as offsets to the Company’s income tax provision. Also under the new standard, for the three and nine months ended September 30, 2017, the Company recorded forfeitures of share-based payments of approximately $1 million and $7 million, respectively.
New accounting pronouncements issued but not yet adopted. In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.
In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU No. 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized with an adjustment to retained earnings on January 1, 2018. The Company has substantially completed its internal evaluation of the adoption of this standard, which included a review of all revenue-related contracts with customers and the application of the new revenue recognition model against those contracts. The Company is also updating its revenue recognition policy to conform to the new standard. The Company also expects to expand its revenue recognition related disclosure. Including those changes previously discussed, the Company does not expect this new guidance will have a material impact on its consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company is currently in the process of reviewing all contracts that could be applicable to this new guidance. The Company believes this new guidance will have a moderate impact to its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under currently applicable guidance.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. This new guidance is effective for annual periods beginning after December 15, 2017, and early adoption is allowed. The Company is evaluating the impact this new guidance will have on its consolidated financial statements.
|
The following table reflects the Company’s net capitalized exploratory well activity during the nine months ended September 30, 2017:
Nine Months Ended | |||||||
(in millions) | September 30, 2017 | ||||||
Beginning capitalized exploratory well costs | $ | 151 | |||||
Additions to exploratory well costs pending the determination of proved reserves | 255 | ||||||
Reclassifications due to determination of proved reserves | (136) | ||||||
Ending capitalized exploratory well costs | $ | 270 | |||||
The following table provides an aging at September 30, 2017 and December 31, 2016 of capitalized exploratory well costs based on the date drilling was completed:
September 30, | December 31, | ||||||
(in millions, except number of projects) | 2017 | 2016 | |||||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 266 | $ | 141 | |||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | 4 | 10 | |||||
Total capitalized exploratory well costs | $ | 270 | $ | 151 | |||
Number of projects with exploratory well costs that have been capitalized for a period greater | |||||||
than one year | 4 | 8 | |||||
|
A summary of the Company’s Stock Incentive Plan activity for the nine months ended September 30, 2017 is presented below:
Restricted | Stock | Performance | |||||||||
Stock Shares | Options | Units | |||||||||
Outstanding at December 31, 2016 | 1,157,270 | 20,000 | 331,526 | ||||||||
Awards granted (a) | 445,384 | - | 108,398 | ||||||||
Options exercised | - | (20,000) | - | ||||||||
Awards cancelled / forfeited | (82,200) | - | (43,333) | ||||||||
Lapse of restrictions | (389,965) | - | - | ||||||||
Outstanding at September 30, 2017 | 1,130,489 | - | 396,591 | ||||||||
(a) Weighted average grant date fair value per share/unit | $ | 121.77 | $ | - | $ | 183.48 | |||||
The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at September 30, 2017:
(in millions) | ||||
Remaining 2017 | $ | 17 | ||
2018 | 47 | |||
2019 | 25 | |||
Thereafter | 8 | |||
Total | $ | 97 | ||
|
The following table presents the carrying amounts and fair values of the Company’s financial instruments at September 30, 2017 and December 31, 2016:
September 30, 2017 | December 31, 2016 | |||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||
(in millions) | Value | Value | Value | Value | ||||||||||
Assets: | ||||||||||||||
Derivative instruments | $ | 32 | $ | 32 | $ | 4 | $ | 4 | ||||||
Liabilities: | ||||||||||||||
Derivative instruments | $ | 43 | $ | 43 | $ | 178 | $ | 178 | ||||||
Credit facility | $ | 368 | $ | 368 | $ | - | $ | - | ||||||
$600 million 5.5% senior notes due 2022 (a) | $ | - | $ | - | $ | 594 | $ | 620 | ||||||
$1,550 million 5.5% senior notes due 2023 (a) | $ | - | $ | - | $ | 1,555 | $ | 1,621 | ||||||
$600 million 4.375% senior notes due 2025 (a) | $ | 593 | $ | 632 | $ | 592 | $ | 599 | ||||||
$1,000 million 3.75% senior notes due 2027 (a) | $ | 988 | $ | 1,006 | $ | - | $ | - | ||||||
$800 million 4.875% senior notes due 2047 (a) | $ | 789 | $ | 834 | $ | - | $ | - | ||||||
(a) | The carrying value includes associated deferred loan costs and any premium (discount). |
The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at September 30, 2017 and December 31, 2016. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.
September 30, 2017 | ||||||||||||||||||||||
Fair Value Measurements Using | Net | |||||||||||||||||||||
Quoted Prices | Gross | Fair Value | ||||||||||||||||||||
in Active | Significant | Amounts | Presented | |||||||||||||||||||
Markets for | Other | Significant | Offset in the | in the | ||||||||||||||||||
Identical | Observable | Unobservable | Consolidated | Consolidated | ||||||||||||||||||
Assets | Inputs | Inputs | Total | Balance | Balance | |||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Fair Value | Sheet | Sheet | ||||||||||||||||
Assets: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | $ | - | $ | 35 | $ | - | $ | 35 | $ | (31) | $ | 4 | ||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | 44 | - | 44 | (16) | 28 | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | - | (68) | - | (68) | 31 | (37) | ||||||||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | (22) | - | (22) | 16 | (6) | ||||||||||||||||
Net derivative instruments | $ | - | $ | (11) | $ | - | $ | (11) | $ | - | $ | (11) | ||||||||||
December 31, 2016 | ||||||||||||||||||||||
Fair Value Measurements Using | Net | |||||||||||||||||||||
Quoted Prices | Gross | Fair Value | ||||||||||||||||||||
in Active | Significant | Amounts | Presented | |||||||||||||||||||
Markets for | Other | Significant | Offset in the | in the | ||||||||||||||||||
Identical | Observable | Unobservable | Consolidated | Consolidated | ||||||||||||||||||
Assets | Inputs | Inputs | Total | Balance | Balance | |||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Fair Value | Sheet | Sheet | ||||||||||||||||
Assets: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | $ | - | $ | 59 | $ | - | $ | 59 | $ | (55) | $ | 4 | ||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | - | - | - | - | - | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||
Current: | ||||||||||||||||||||||
Commodity derivatives | - | (137) | - | (137) | 55 | (82) | ||||||||||||||||
Noncurrent: | ||||||||||||||||||||||
Commodity derivatives | - | (96) | - | (96) | - | (96) | ||||||||||||||||
Net derivative instruments | $ | - | $ | (174) | $ | - | $ | (174) | $ | - | $ | (174) | ||||||||||
The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated period:
Estimated | |||||||||
Carrying | Fair Value | Impairment | |||||||
(in millions) | Amount | (Level 3) | Expense | ||||||
March 2016 | $ | 3,438 | $ | 1,913 | $ | 1,525 | |||
|
The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three and nine months ended September 30, 2017 and 2016:
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Gain (loss) on derivatives: | ||||||||||||||
Oil derivatives | $ | (205) | $ | 36 | $ | 260 | $ | (173) | ||||||
Natural gas derivatives | (1) | 5 | 29 | (3) | ||||||||||
Total | $ | (206) | $ | 41 | $ | 289 | $ | (176) | ||||||
The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2017 and 2016: | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Net cash receipts from (payments on) derivatives: | ||||||||||||||
Oil derivatives | $ | 28 | $ | 154 | $ | 129 | $ | 566 | ||||||
Natural gas derivatives | 2 | 1 | (3) | 16 | ||||||||||
Total | $ | 30 | $ | 155 | $ | 126 | $ | 582 | ||||||
The following table sets forth the Company’s outstanding derivative contracts at September 30, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 2017 are expected to settle by December 31, 2019.
First | Second | Third | Fourth | ||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||
Oil Price Swaps: (a) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 9,370,080 | 9,370,080 | |||||||||||
Price per Bbl | $ | 51.33 | $ | 51.33 | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 8,180,629 | 7,546,170 | 7,064,318 | 6,676,007 | 29,467,124 | ||||||||
Price per Bbl | $ | 51.54 | $ | 51.45 | $ | 51.36 | $ | 51.26 | $ | 51.41 | |||
2019: | |||||||||||||
Volume (Bbl) | 5,314,000 | 5,090,000 | 4,897,000 | 4,721,000 | 20,022,000 | ||||||||
Price per Bbl | $ | 52.54 | $ | 52.52 | $ | 52.54 | $ | 52.55 | $ | 52.54 | |||
Oil Basis Swaps: (b) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 8,508,000 | 8,508,000 | |||||||||||
Price per Bbl | $ | (0.74) | $ | (0.74) | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 7,936,000 | 7,521,000 | 6,961,000 | 6,684,000 | 29,102,000 | ||||||||
Price per Bbl | $ | (1.02) | $ | (1.01) | $ | (1.01) | $ | (1.01) | $ | (1.01) | |||
2019: | |||||||||||||
Volume (Bbl) | 4,581,000 | 4,428,000 | 4,262,000 | 4,139,000 | 17,410,000 | ||||||||
Price per Bbl | $ | (1.17) | $ | (1.17) | $ | (1.18) | $ | (1.18) | $ | (1.17) | |||
Natural Gas Price Swaps: (c) | |||||||||||||
2017: | |||||||||||||
Volume (MMBtu) | 14,673,000 | 14,673,000 | |||||||||||
Price per MMBtu | $ | 3.10 | $ | 3.10 | |||||||||
2018: | |||||||||||||
Volume (MMBtu) | 11,156,000 | 10,641,000 | 10,219,000 | 9,904,000 | 41,920,000 | ||||||||
Price per MMBtu | $ | 3.06 | $ | 3.05 | $ | 3.05 | $ | 3.04 | $ | 3.05 | |||
2019: | |||||||||||||
Volume (MMBtu) | 2,791,533 | 2,681,387 | 2,578,537 | 2,489,535 | 10,540,992 | ||||||||
Price per MMBtu | $ | 2.86 | $ | 2.85 | $ | 2.85 | $ | 2.85 | $ | 2.85 | |||
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. | |||||||||||||
(b) The basis differential price is between Midland – WTI and Cushing – WTI. | |||||||||||||
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. | |||||||||||||
|
The Company’s debt consisted of the following at September 30, 2017 and December 31, 2016:
September 30, | December 31, | |||||||
(in millions) | 2017 | 2016 | ||||||
Credit facility | $ | 368 | $ | - | ||||
5.5% unsecured senior notes due 2022 | - | 600 | ||||||
5.5% unsecured senior notes due 2023 | - | 1,550 | ||||||
4.375% unsecured senior notes due 2025 | 600 | 600 | ||||||
3.75% unsecured senior notes due 2027 | 1,000 | - | ||||||
4.875% unsecured senior notes due 2047 | 800 | - | ||||||
Unamortized original issue premium (discount), net | (6) | 22 | ||||||
Senior notes issuance costs, net | (24) | (31) | ||||||
Less: current portion | - | - | ||||||
Total long-term debt | $ | 2,738 | $ | 2,741 | ||||
As a result of these transactions, the Company recorded a loss on extinguishment of debt for the three and nine months ended September 30, 2017 as follows:
(in millions) | Tender Offer | Extinguishment | Total | ||||||||
Tender premium | $ | 36 | $ | - | $ | 36 | |||||
Make-whole premium | - | 25 | 25 | ||||||||
Prepaid interest | - | 2 | 2 | ||||||||
Unamortized original issue premium | (11) | (8) | (19) | ||||||||
Unamortized deferred loan costs | 12 | 9 | 21 | ||||||||
Total loss on extinguishment of debt | $ | 37 | $ | 28 | $ | 65 | |||||
Principal maturities of long-term debt outstanding at September 30, 2017 were as follows:
(in millions) | |||||
Remaining 2017 | $ | - | |||
2018 | - | ||||
2019 | - | ||||
2020 | - | ||||
2021 | - | ||||
2022 | 368 | ||||
Thereafter | 2,400 | ||||
Total | $ | 2,768 | |||
The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2017 and 2016:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Cash payments for interest | $ | 73 | $ | 109 | $ | 138 | $ | 215 | ||||||||
Non-cash interest | 1 | 3 | 5 | 7 | ||||||||||||
Net changes in accruals | (35) | (59) | (25) | (60) | ||||||||||||
Total interest expense | $ | 39 | $ | 53 | $ | 118 | $ | 162 | ||||||||
|
The following table summarizes the Company’s commitments at September 30, 2017:
(in millions) | ||||
Remaining 2017 | $ | 10 | ||
2018 | 40 | |||
2019 | 59 | |||
2020 | 32 | |||
2021 | 31 | |||
2022 | 26 | |||
Thereafter | 88 | |||
Total | $ | 286 | ||
Future minimum lease commitments under non-cancellable operating leases at September 30, 2017 were as follows:
(in millions) | ||||
Remaining 2017 | $ | 2 | ||
2018 | 9 | |||
2019 | 7 | |||
2020 | 6 | |||
2021 | 4 | |||
2022 | - | |||
Thereafter | 1 | |||
Total | $ | 29 | ||
|
The following condensed consolidating balance sheets at September 30, 2017 and December 31, 2016, condensed consolidating statements of operations for the three and nine months ended September 30, 2017 and 2016 and condensed consolidating statements of cash flows for the nine months ended September 30, 2017 and 2016, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.
Condensed Consolidating Balance Sheet | ||||||||||||||||
September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
ASSETS | ||||||||||||||||
Accounts receivable - related parties | $ | 8,903 | $ | (653) | $ | - | $ | (8,250) | $ | - | ||||||
Other current assets | 14 | 515 | 6 | - | 535 | |||||||||||
Oil and natural gas properties, net | - | 11,968 | 619 | - | 12,587 | |||||||||||
Property and equipment, net | - | 232 | - | - | 232 | |||||||||||
Investment in subsidiaries | 2,963 | - | - | (2,963) | - | |||||||||||
Other long-term assets | 42 | 86 | - | - | 128 | |||||||||||
Total assets | $ | 11,922 | $ | 12,148 | $ | 625 | $ | (11,213) | $ | 13,482 | ||||||
LIABILITIES AND EQUITY | ||||||||||||||||
Accounts payable - related parties | $ | (653) | $ | 8,290 | $ | 613 | $ | (8,250) | $ | - | ||||||
Other current liabilities | 50 | 756 | 4 | - | 810 | |||||||||||
Long-term debt | 2,738 | - | - | - | 2,738 | |||||||||||
Other long-term liabilities | 1,156 | 141 | 6 | - | 1,303 | |||||||||||
Equity | 8,631 | 2,961 | 2 | (2,963) | 8,631 | |||||||||||
Total liabilities and equity | $ | 11,922 | $ | 12,148 | $ | 625 | $ | (11,213) | $ | 13,482 | ||||||
Condensed Consolidating Balance Sheet | |||||||||||||
December 31, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
ASSETS | |||||||||||||
Accounts receivable - related parties | $ | 8,991 | $ | (336) | $ | (8,655) | $ | - | |||||
Other current assets | 12 | 534 | - | 546 | |||||||||
Oil and natural gas properties, net | - | 11,086 | - | 11,086 | |||||||||
Property and equipment, net | - | 216 | - | 216 | |||||||||
Investment in subsidiaries | 1,989 | - | (1,989) | - | |||||||||
Other long-term assets | 11 | 260 | - | 271 | |||||||||
Total assets | $ | 11,003 | $ | 11,760 | $ | (10,644) | $ | 12,119 | |||||
LIABILITIES AND EQUITY | |||||||||||||
Accounts payable - related parties | $ | (336) | $ | 8,991 | $ | (8,655) | $ | - | |||||
Other current liabilities | 114 | 639 | - | 753 | |||||||||
Long-term debt | 2,741 | - | - | 2,741 | |||||||||
Other long-term liabilities | 861 | 141 | - | 1,002 | |||||||||
Equity | 7,623 | 1,989 | (1,989) | 7,623 | |||||||||
Total liabilities and equity | $ | 11,003 | $ | 11,760 | $ | (10,644) | $ | 12,119 | |||||
The following condensed consolidating balance sheets at September 30, 2017 and December 31, 2016, condensed consolidating statements of operations for the three and nine months ended September 30, 2017 and 2016 and condensed consolidating statements of cash flows for the nine months ended September 30, 2017 and 2016, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.
Condensed Consolidating Statement of Operations | ||||||||||||||||
Three Months Ended September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
Total operating revenues | $ | - | $ | 619 | $ | 8 | $ | - | $ | 627 | ||||||
Total operating costs and expenses | (207) | (491) | (6) | - | (704) | |||||||||||
Income (loss) from operations | (207) | 128 | 2 | - | (77) | |||||||||||
Interest expense | (39) | - | - | - | (39) | |||||||||||
Loss on extinguishment of debt | (65) | - | - | - | (65) | |||||||||||
Other, net | 132 | 2 | - | (132) | 2 | |||||||||||
Income (loss) before income | ||||||||||||||||
taxes | (179) | 130 | 2 | (132) | (179) | |||||||||||
Income tax benefit | 66 | - | - | - | 66 | |||||||||||
Net income (loss) | $ | (113) | $ | 130 | $ | 2 | $ | (132) | $ | (113) | ||||||
Condensed Consolidating Statement of Operations | |||||||||||||
Three Months Ended September 30, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
Total operating revenues | $ | - | $ | 430 | $ | - | $ | 430 | |||||
Total operating costs and expenses | 41 | (469) | - | (428) | |||||||||
Income (loss) from operations | 41 | (39) | - | 2 | |||||||||
Interest expense | (52) | (1) | - | (53) | |||||||||
Loss on extinguishment of debt | (28) | - | - | (28) | |||||||||
Other, net | (42) | (2) | 42 | (2) | |||||||||
Loss before income taxes | (81) | (42) | 42 | (81) | |||||||||
Income tax benefit | 30 | - | - | 30 | |||||||||
Net loss | $ | (51) | $ | (42) | $ | 42 | $ | (51) | |||||
Condensed Consolidating Statement of Operations | ||||||||||||||||
Nine Months Ended September 30, 2017 | ||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | |||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | |||||||||||
Total operating revenues | $ | - | $ | 1,798 | $ | 8 | $ | - | $ | 1,806 | ||||||
Total operating costs and expenses | 288 | (835) | (6) | - | (553) | |||||||||||
Income from operations | 288 | 963 | 2 | - | 1,253 | |||||||||||
Interest expense | (117) | (1) | - | - | (118) | |||||||||||
Loss on extinguishment of debt | (66) | - | - | - | (66) | |||||||||||
Other, net | 982 | 18 | - | (982) | 18 | |||||||||||
Income before income taxes | 1,087 | 980 | 2 | (982) | 1,087 | |||||||||||
Income tax expense | (398) | - | - | - | (398) | |||||||||||
Net income | $ | 689 | $ | 980 | $ | 2 | $ | (982) | $ | 689 | ||||||
Condensed Consolidating Statement of Operations | |||||||||||||
Nine Months Ended September 30, 2016 | |||||||||||||
Parent | Subsidiary | Consolidating | |||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | |||||||||
Total operating revenues | $ | - | $ | 1,110 | $ | - | $ | 1,110 | |||||
Total operating costs and expenses | (177) | (2,853) | - | (3,030) | |||||||||
Loss from operations | (177) | (1,743) | - | (1,920) | |||||||||
Interest expense | (159) | (3) | - | (162) | |||||||||
Loss on extinguishment of debt | (28) | - | - | (28) | |||||||||
Other, net | (1,755) | (10) | 1,756 | (9) | |||||||||
Loss before income taxes | (2,119) | (1,756) | 1,756 | (2,119) | |||||||||
Income tax benefit | 782 | - | - | 782 | |||||||||
Net loss | $ | (1,337) | $ | (1,756) | $ | 1,756 | $ | (1,337) | |||||
The following condensed consolidating balance sheets at September 30, 2017 and December 31, 2016, condensed consolidating statements of operations for the three and nine months ended September 30, 2017 and 2016 and condensed consolidating statements of cash flows for the nine months ended September 30, 2017 and 2016, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.
Condensed Consolidating Statement of Cash Flows | |||||||||||||||||
Nine Months Ended September 30, 2017 | |||||||||||||||||
Parent | Subsidiary | Subsidiary | Consolidating | ||||||||||||||
(in millions) | Issuer | Guarantors | Non-Guarantors | Entries | Total | ||||||||||||
Net cash flows provided by operating activities | $ | 99 | $ | 1,084 | $ | 2 | $ | - | $ | 1,185 | |||||||
Net cash flows used in investing activities | - | (592) | (615) | - | (1,207) | ||||||||||||
Net cash flows provided by (used in) financing | |||||||||||||||||
activities | (99) | (545) | 613 | - | (31) | ||||||||||||
Net decrease in cash and cash equivalents | - | (53) | - | - | (53) | ||||||||||||
Cash and cash equivalents at beginning of period | - | 53 | - | - | 53 | ||||||||||||
Cash and cash equivalents at end of period | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||
Nine Months Ended September 30, 2016 | ||||||||||||||
Parent | Subsidiary | Consolidating | ||||||||||||
(in millions) | Issuer | Guarantors | Entries | Total | ||||||||||
Net cash flows provided by (used in) operating activities | $ | (694) | $ | 1,713 | $ | - | $ | 1,019 | ||||||
Net cash flows used in investing activities | - | (783) | - | (783) | ||||||||||
Net cash flows provided by financing activities | 694 | - | - | 694 | ||||||||||
Net increase in cash and cash equivalents | - | 930 | - | 930 | ||||||||||
Cash and cash equivalents at beginning of period | - | 229 | - | 229 | ||||||||||
Cash and cash equivalents at end of period | $ | - | $ | 1,159 | $ | - | $ | 1,159 | ||||||
|
After September 30, 2017, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:
First | Second | Third | Fourth | ||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||
Oil Price Swaps: (a) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 846,000 | 846,000 | |||||||||||
Price per Bbl | $ | 51.29 | $ | 51.29 | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 953,000 | 600,000 | 407,000 | 296,000 | 2,256,000 | ||||||||
Price per Bbl | $ | 51.55 | $ | 51.39 | $ | 51.43 | $ | 51.28 | $ | 51.45 | |||
2019: | |||||||||||||
Volume (Bbl) | 1,035,000 | 1,046,500 | 828,000 | 828,000 | 3,737,500 | ||||||||
Price per Bbl | $ | 51.25 | $ | 51.25 | $ | 51.14 | $ | 51.14 | $ | 51.20 | |||
Oil Basis Swaps: (b) | |||||||||||||
2017: | |||||||||||||
Volume (Bbl) | 1,499,000 | 1,499,000 | |||||||||||
Price per Bbl | $ | (0.12) | $ | (0.12) | |||||||||
2018: | |||||||||||||
Volume (Bbl) | 540,000 | 546,000 | 276,000 | 276,000 | 1,638,000 | ||||||||
Price per Bbl | $ | (0.21) | $ | (0.21) | $ | (0.38) | $ | (0.38) | $ | (0.27) | |||
2019: | |||||||||||||
Volume (Bbl) | 1,395,000 | 1,410,500 | 1,426,000 | 1,426,000 | 5,657,500 | ||||||||
Price per Bbl | $ | (0.68) | $ | (0.68) | $ | (0.68) | $ | (0.68) | $ | (0.68) | |||
Natural Gas Price Swaps: (c) | |||||||||||||
2017: | |||||||||||||
Volume (MMBtu) | 3,660,000 | 3,660,000 | |||||||||||
Price per MMBtu | $ | 3.02 | $ | 3.02 | |||||||||
2018: | |||||||||||||
Volume (MMBtu) | 5,400,000 | 5,460,000 | 4,600,000 | 4,600,000 | 20,060,000 | ||||||||
Price per MMBtu | $ | 3.02 | $ | 3.02 | $ | 3.01 | $ | 3.01 | $ | 3.02 | |||
2019: | |||||||||||||
Volume (MMBtu) | 1,800,000 | 1,820,000 | 1,840,000 | 1,840,000 | 7,300,000 | ||||||||
Price per MMBtu | $ | 2.86 | $ | 2.86 | $ | 2.86 | $ | 2.86 | $ | 2.86 | |||
(a) | The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price. | ||||||||||||
(b) | The basis differential price is between Midland – WTI and Cushing – WTI. | ||||||||||||
(c) | The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. | ||||||||||||
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Capitalized costs
September 30, | December 31, | |||||||
(in millions) | 2017 | 2016 | ||||||
Oil and natural gas properties: | ||||||||
Proved | $ | 17,950 | $ | 16,620 | ||||
Unproved | 2,804 | 1,856 | ||||||
Less: accumulated depletion | (8,167) | (7,390) | ||||||
Net capitalized costs for oil and natural gas properties | $ | 12,587 | $ | 11,086 | ||||
Costs incurred for oil and natural gas producing activities
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||
Property acquisition costs: | ||||||||||||||
Proved | $ | 162 | $ | 1 | $ | 301 | $ | 257 | ||||||
Unproved | 472 | 14 | 865 | 172 | ||||||||||
Exploration | 252 | 177 | 725 | 513 | ||||||||||
Development | 175 | 97 | 478 | 287 | ||||||||||
Total costs incurred for oil and natural gas properties | $ | 1,061 | $ | 289 | $ | 2,369 | $ | 1,229 | ||||||
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