Document And Entity Information
Document And Entity Information | 9 Months Ended |
Sep. 30, 2017shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | NOBLE ENERGY INC |
Entity Central Index Key | 72,207 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Large Accelerated Filer |
Entity Common Stock, Shares Outstanding | 486,607,284 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | Q3 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Sep. 30, 2017 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Loss - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Revenues | ||||
Oil, NGL and Gas Sales | $ 907 | $ 882 | $ 2,918 | $ 2,411 |
Income from Equity Method Investees and Other | 53 | 28 | 137 | 70 |
Total | 960 | 910 | 3,055 | 2,481 |
Costs and Expenses | ||||
Production Expense | 280 | 282 | 866 | 839 |
Exploration Expense | 64 | 125 | 136 | 376 |
Depreciation, Depletion and Amortization | 523 | 621 | 1,554 | 1,859 |
Loss on Marcellus Shale Upstream Divestiture | 4 | 0 | 2,326 | 0 |
General and Administrative | 102 | 95 | 304 | 293 |
Other Operating (Income) Expense, Net | (15) | 37 | 132 | 127 |
Total | 958 | 1,160 | 5,318 | 3,494 |
Operating Income (Loss) | 2 | (250) | (2,263) | (1,013) |
Other Expense | ||||
Loss (Gain) on Commodity Derivative Instruments | 22 | (55) | (145) | 53 |
Loss (Gain) on Extinguishment of Debt | 98 | 0 | 98 | (80) |
Interest, Net of Amount Capitalized | 88 | 86 | 271 | 242 |
Other Non-Operating Expense (Income), Net | 2 | (1) | (4) | 3 |
Total | 210 | 30 | 220 | 218 |
Loss Before Income Taxes | (208) | (280) | (2,483) | (1,231) |
Income Tax Benefit | (93) | (137) | (917) | (486) |
Net Loss and Comprehensive Loss Including Noncontrolling Interests | (115) | (143) | (1,566) | (745) |
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 21 | 1 | 46 | 1 |
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ (136) | $ (144) | $ (1,612) | $ (746) |
Net Loss Attributable to Noble Energy per Common Share - Basic and Diluted ($ per share) | $ (0.28) | $ (0.33) | $ (3.47) | $ (1.73) |
Weighted Average Number of Common Shares Outstanding | ||||
Basic and Diluted (in shares) | 487 | 430 | 464 | 430 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and Cash Equivalents | $ 564 | $ 1,180 |
Accounts Receivable, Net | 675 | 615 |
Other Current Assets | 303 | 160 |
Total Current Assets | 1,542 | 1,955 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method of Accounting) | 30,583 | 30,355 |
Property, Plant and Equipment, Other | 928 | 909 |
Total Property, Plant and Equipment, Gross | 31,511 | 31,264 |
Accumulated Depreciation, Depletion and Amortization | (13,115) | (12,716) |
Total Property, Plant and Equipment, Net | 18,396 | 18,548 |
Goodwill | 1,295 | 0 |
Other Noncurrent Assets | 416 | 508 |
Total Assets | 21,649 | 21,011 |
Current Liabilities | ||
Accounts Payable - Trade | 1,123 | 736 |
Other Current Liabilities | 499 | 742 |
Total Current Liabilities | 1,622 | 1,478 |
Long-Term Debt | 7,487 | 7,011 |
Deferred Income Taxes | 1,352 | 1,819 |
Other Noncurrent Liabilities | 1,245 | 1,103 |
Total Liabilities | 11,706 | 11,411 |
Commitments and Contingencies | ||
Shareholders’ Equity | ||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | 0 | 0 |
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 529 Million and 471 Million Shares Issued, respectively | 5 | 5 |
Additional Paid in Capital | 8,415 | 6,450 |
Accumulated Other Comprehensive Loss | (29) | (31) |
Treasury Stock, at Cost; 39 Million and 38 Million Shares, respectively | (728) | (692) |
Retained Earnings | 1,803 | 3,556 |
Noble Energy Share of Equity | 9,466 | 9,288 |
Noncontrolling Interests | 477 | 312 |
Total Equity | 9,943 | 9,600 |
Total Liabilities and Equity | $ 21,649 | $ 21,011 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Sep. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value per share (in dollars per share) | $ 1 | $ 1 |
Preferred stock, shares authorized (in shares) | 4,000,000 | 4,000,000 |
Preferred stock, shares issued (in shares) | 0 | 0 |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued (in shares) | 529,000,000 | 471,000,000 |
Treasury stock, shares (in shares) | 39,000,000 | 38,000,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Cash Flows From Operating Activities | ||
Net Loss Including Noncontrolling Interests | $ (1,566) | $ (745) |
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities | ||
Depreciation, Depletion and Amortization | 1,554 | 1,859 |
Loss on Marcellus Shale Upstream Divestiture | 2,326 | 0 |
Deferred Income Tax Benefit | (988) | (699) |
Dry Hole Cost | 2 | 105 |
Undeveloped Leasehold Impairment | 51 | 81 |
Loss (Gain) on Extinguishment of Debt | 98 | (80) |
(Gain) Loss on Commodity Derivative Instruments | (145) | 53 |
Net Cash Received in Settlement of Commodity Derivative Instruments | 18 | 454 |
Stock Based Compensation | 83 | 61 |
Other Adjustments for Noncash Items Included in Income | 12 | 136 |
Changes in Operating Assets and Liabilities | ||
(Increase) Decrease in Accounts Receivable | (148) | 6 |
Increase (Decrease) in Accounts Payable | 230 | (124) |
(Decrease) Increase in Current Income Taxes Payable | (41) | 82 |
Other Current Assets and Liabilities, Net | (5) | (72) |
Other Operating Assets and Liabilities, Net | (63) | (63) |
Net Cash Provided by Operating Activities | 1,418 | 1,054 |
Cash Flows From Investing Activities | ||
Additions to Property, Plant and Equipment | (1,956) | (1,164) |
Proceeds from Marcellus Shale Upstream Divestiture | 1,028 | 0 |
Clayton Williams Energy Acquisition | (616) | 0 |
Other Acquisitions | (327) | 0 |
Additions to Equity Method Investments | (68) | (8) |
Proceeds from Divestitures and Other | 129 | 786 |
Net Cash Used in Investing Activities | (1,810) | (386) |
Cash Flows From Financing Activities | ||
Dividends Paid, Common Stock | (141) | (129) |
Proceeds from Noble Midstream Services Revolving Credit Facility | 245 | 0 |
Repayment of Noble Midstream Services Revolving Credit Facility | (45) | 0 |
Proceeds from Term Loan Facility | 0 | 1,400 |
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 138 | 299 |
Proceeds from Revolving Credit Facility | 1,585 | 0 |
Repayment of Revolving Credit Facility | (1,310) | 0 |
Repayment of Clayton Williams Energy Long-term Debt | (595) | 0 |
Proceeds from Issuance of Senior Notes, Net | 1,086 | 0 |
Repayment of Senior Notes | (1,096) | (1,383) |
Other | (91) | (64) |
Net Cash (Used in) Provided by Financing Activities | (224) | 123 |
(Decrease) Increase in Cash and Cash Equivalents | (616) | 791 |
Cash and Cash Equivalents at Beginning of Period | 1,180 | 1,028 |
Cash and Cash Equivalents at End of Period | $ 564 | $ 1,819 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Common Stock | Additional Paid in Capital | Accumulated Other Comprehensive Loss | Treasury Stock at Cost | Retained Earnings | Non- controlling Interests |
Balance at Beginning of Period at Dec. 31, 2015 | $ 10,370 | $ 5 | $ 6,360 | $ (33) | $ (688) | $ 4,726 | $ 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (745) | (746) | 1 | ||||
Stock-based Compensation | 57 | 57 | |||||
Dividends (30 cents per share) | (129) | (129) | |||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 299 | 299 | |||||
Other | (7) | 1 | (8) | ||||
Balance at End of Period at Sep. 30, 2016 | 9,845 | 5 | 6,417 | (32) | (696) | 3,851 | 300 |
Balance at Beginning of Period at Dec. 31, 2016 | 9,600 | 5 | 6,450 | (31) | (692) | 3,556 | 312 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (1,566) | (1,612) | 46 | ||||
Clayton Williams Energy Acquisition | 1,851 | 1,876 | (25) | ||||
Stock-based Compensation | 80 | 80 | |||||
Dividends (30 cents per share) | (141) | (141) | |||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 138 | 138 | |||||
Distributions to Noncontrolling Interest Owners | (19) | (19) | |||||
Other | 9 | 2 | (11) | ||||
Balance at End of Period at Sep. 30, 2017 | $ 9,943 | $ 5 | $ 8,415 | $ (29) | $ (728) | $ 1,803 | $ 477 |
Consolidated Statements of Equ7
Consolidated Statements of Equity (Parenthetical) - $ / shares | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Statement of Stockholders' Equity [Abstract] | ||
Cash Dividends per share (in dollars per share) | $ 0.3 | $ 0.3 |
Organization and Nature of Oper
Organization and Nature of Operations | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | 1. Organization and Nature of Operations Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico; Eastern Mediterranean; and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. |
Basis of Presentation
Basis of Presentation | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | 2. Basis of Presentation Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2017 and December 31, 2016 and for the three and nine months ended September 30, 2017 and 2016 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is materially consistent with comprehensive income or loss. In Note 11. Segment Information , we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (NYSE: NBLX) (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. Goodwill As of September 30, 2017 , our consolidated balance sheet includes goodwill of $1.3 billion . This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017 , and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit. See Note 3. Clayton Williams Energy Acquisition . Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for newly issued accounting guidance regarding future goodwill impairment testing. We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill. Certain negative indicators included the current commodity price environment (driven by several macroeconomic factors) coupled with onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as our current and future drilling and development plans for our Texas assets, synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability. Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware basin. Having assessed the totality of such events and circumstances described above, we determined that while there exist certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with the conduct of Step 1 of the impairment test as part of our annual review. As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, by approximately 6% and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017. If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Our exit costs in 2017 relate primarily to estimated costs associated with a retained Marcellus Shale firm transportation contract, for which we accrued an exit liability at June 30, 2017. The recognition and fair value estimation of a liability requires that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies . Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Reserves Estimates Estimated quantities of crude oil, natural gas and natural gas liquids (NGL) reserves are the most significant of our estimates. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available engineering and geoscience information and also interpretation of the provided data. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. During the first nine months of 2017, we recorded the following significant changes in our proved reserves estimates: • Leviathan Field In second quarter 2017, we recorded proved undeveloped reserves of 551 MMBoe, net, for the Leviathan field, offshore Israel, upon approval and sanction of the first phase of development, and are expecting to initiate natural gas production by the end of 2019. • Tamar Field In third quarter 2017, we completed additional reservoir modeling reflecting integration of the Tamar 8 well results into our geologic modeling across the reservoir and, as a result, we added one Tcfe, gross, or 48 MMBoe, net, for the Tamar Field, offshore Israel, of proved developed natural gas reserves as of September 30, 2017. • Delaware Basin We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves as of June 30, 2017 related to the Clayton Williams Energy Acquisition. • Marcellus Shale The Marcellus Shale upstream divestiture resulted in a decrease in net proved reserves of approximately 241 MMBoe as of June 30, 2017, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves. Recently Issued Accounting Standards Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition. We continue to evaluate the impact of the ASU on our accounting policies, internal controls, and consolidated financial statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing accounting policies to address the provisions of the ASU. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. The ASU also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of our future revenues and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect the ASU to have a material effect on the timing of revenue recognition or our financial position. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach with a cumulative adjustment to retained earnings as necessary. Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We do not believe adoption of ASU 2017-09 will have a material impact on our financial statements. We will adopt the new standard on the effective date of January 1, 2018. Business Combinations: Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of transactions to be accounted for as business transactions, which take more time and cost more to analyze than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition is not impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption on January 1, 2018. Statement of Cash Flows: Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash , which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. We will adopt the new standard on the effective date of January 1, 2018. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments , to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. We will adopt the new standard on the effective date of January 1, 2018. Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. At this time, we cannot reasonably estimate the financial impact this ASU will have on our financial statements; however, we believe adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. We will adopt the new standard on the effective date of January 1, 2019. Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt. Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. We will adopt the new standard on the effective date of January 1, 2020. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Production Expense Lease Operating Expense $ 151 $ 131 $ 414 $ 412 Production and Ad Valorem Taxes 36 30 119 73 Gathering, Transportation and Processing Expense (1) 93 121 333 354 Total $ 280 $ 282 $ 866 $ 839 Exploration Expense Leasehold Impairment and Amortization (2) $ 33 $ 96 $ 51 $ 127 Dry Hole Cost (3) 2 5 2 105 Seismic, Geological and Geophysical 7 15 20 47 Staff Expense 11 15 40 53 Other 11 (6 ) 23 44 Total $ 64 $ 125 $ 136 $ 376 Loss on Marcellus Shale Upstream Divestiture (4) Loss on Sale $ — $ — $ 2,270 $ — Firm Transportation Commitment (5) — — 41 — Other (6) 4 — 15 — Total $ 4 $ — $ 2,326 $ — Other Operating Expense, Net (7) Marketing Expense (1) (8) $ 6 $ 12 $ 39 $ 39 Clayton Williams Energy Acquisition Expenses (9) 4 — 98 — Loss on Asset Due to Terminated Contract (10) — — — 47 North Sea Remediation Project Revision (11) (42 ) — (42 ) — Other, Net 17 25 37 41 Total $ (15 ) $ 37 $ 132 $ 127 (1) Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the three and nine months ended September 30, 2017 , these costs totaled $12 million and $17 million , respectively. For the three and nine months ended September 30, 2016 , these costs totaled $8 million and $19 million , respectively, and have been reclassified from marketing expense to conform to the current presentation. (2) See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) For the nine months ended September 30, 2016, amount related primarily to the Silvergate exploratory well, Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel. (4) See Note 4. Acquisitions and Divestitures . (5) Amount represents expense related to an unutilized firm transportation commitment associated with a Marcellus Shale firm transportation contract. See Note 12. Commitments and Contingencies . (6) Amount includes costs for legal and advisory services and employee severance charges. (7) (Gain)/Loss on debt extinguishment was historically presented as a component of other operating expense, net in our consolidated statements of operations. Beginning with third quarter 2017, we have changed our presentation to reflect these as a separate line item within other expense (income) below operating loss. The prior periods have been reclassified to conform to that presentation. (8) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (9) See Note 3. Clayton Williams Energy Acquisition . (10) Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance. (11) See Note 9. Asset Retirement Obligations . Balance Sheet Information Other balance sheet information is as follows: (millions) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 403 $ 403 Joint Interest Billings 183 106 Proceeds Receivable (1) — 40 Other 106 86 Allowance for Doubtful Accounts (17 ) (20 ) Total $ 675 $ 615 Other Current Assets Inventories, Materials and Supplies $ 61 $ 71 Inventories, Crude Oil 17 18 Assets Held for Sale (2) 180 18 Restricted Cash (3) — 30 Prepaid Expenses and Other Current Assets 45 23 Total $ 303 $ 160 Other Noncurrent Assets Equity Method Investments $ 286 $ 400 Mutual Fund Investments 70 71 Other Assets, Noncurrent 60 37 Total $ 416 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 118 $ 115 Commodity Derivative Liabilities 4 102 Income Taxes Payable 13 53 Asset Retirement Obligations (4) 50 160 Interest Payable 82 76 Current Portion of Capital Lease Obligations 65 63 Foreign Sales Tax Payable 29 14 Compensation and Benefits Payable 87 110 Theoretical Withdrawal Premium 25 18 Other Liabilities, Current (5) 26 31 Total $ 499 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 216 $ 218 Asset Retirement Obligations (4) 894 775 Marcellus Shale Firm Transportation Commitment (6) 31 — Production and Ad Valorem Taxes 49 47 Other Liabilities, Noncurrent 55 63 Total $ 1,245 $ 1,103 (1) Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017. See Note 4. Acquisitions and Divestitures . (2) Balance at September 30, 2017 primarily includes our equity investment in CONE Gathering, LLC. See Note 4. Acquisitions and Divestitures . (3) Balance at December 31, 2016 represented amount held in escrow for the purchase of certain Delaware Basin properties. The transaction closed in first quarter 2017. See Note 4. Acquisitions and Divestitures . (4) Reclassification from current to noncurrent is driven primarily by a change in expected timing of abandonment activities in the Gulf of Mexico. See Note 9. Asset Retirement Obligations . (5) Balance at September 30, 2017 includes $8 million associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies . (6) See Note 12. Commitments and Contingencies . |
Clayton Williams Energy Acquisi
Clayton Williams Energy Acquisition | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Clayton Williams Energy Acquisition | 3. Clayton Williams Energy Acquisition In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholders and closed on April 24, 2017 . Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the Permian and Midland Basins. In total, the acquisition increased our Delaware Basin position to approximately 118,000 net acres. We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves, as of June 30, 2017. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering. The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million , for total consideration of approximately $2.5 billion , in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $ 1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 6. Debt . In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $98 million to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees, and $34 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted shares and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance. Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Clayton Williams Energy to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not expected to be deductible for income tax purposes. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final tax returns that provide the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate. The following table sets forth our preliminary purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,876 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,513 Plus Liabilities Assumed by Noble Energy: Accounts Payable 67 Other Current Liabilities 38 Long-Term Deferred Tax Liability 520 Long-Term Debt 595 Asset Retirement Obligations 58 Total Purchase Price Plus Liabilities Assumed $ 3,791 The fair value of Clayton Williams Energy's identifiable assets is as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 63 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Cost 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 58 Other Noncurrent Assets 13 Implied Goodwill 1,295 Total Asset Value $ 3,791 In connection with the acquisition, we assumed, and then subsequently retired, $595 million of Clayton Williams Energy long-term debt. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs. The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin. The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017 . We generated revenues of $56 million and a pre-tax loss of $14 million from the Clayton Williams Energy assets during the period April 24, 2017 to September 30, 2017. Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the three and nine months ended September 30, 2017 were adjusted to exclude acquisition-related costs of $4 million and $98 million , respectively, incurred by Noble Energy and $23 million , incurred by Clayton Williams Energy in second quarter 2017. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. Three Months Ended September 30, Nine Months Ended September 30, (millions, except per share amounts) 2017 (1) 2016 2017 2016 Revenues $ 960 $ 964 $ 3,102 $ 2,605 Net Loss and Comprehensive Loss Attributable to Noble Energy (133 ) (193 ) (1,561 ) (860 ) Net Loss Attributable to Noble Energy per Common Share Basic and Diluted $ (0.27 ) $ (0.40 ) $ (3.21 ) $ (1.77 ) (1) Adjusted for $4 million acquisition-related costs, net of 35% tax, incurred during third quarter 2017. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 9 Months Ended |
Sep. 30, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Divestitures | 4. Acquisitions and Divestitures 2017 Asset Transactions During the first nine months of 2017, we engaged in the following asset transactions. Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which are primarily natural gas properties. The sales price totaled $1.2 billion , and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. To date, conditions for the recognition of the contingent consideration are not probable and therefore, no amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 6. Debt . In second quarter 2017, we recognized a total loss of $2.3 billion , or $1.5 billion after-tax, on this transaction. The aggregate net book value of the properties prior to the sale was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. As part of the total loss, we recorded a charge of $41 million , discounted, relating to a retained transportation contract where the pipeline project is currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. As such, we recorded a charge in accordance with accounting for exit or disposal activities under ASC 420 - Exit or Disposal Cost Obligations. In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projects which are not yet commercially available to us. These projects are either under construction or have not yet been approved by the Federal Energy Regulatory Commission (FERC). As these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation, as well as other restructuring or office closure costs, associated with this exit activity in the future. See Note 2. Basis of Presentation and Note 12. Commitments and Contingencies . For the nine months ended September 30, 2017 , our consolidated statements of operations include a pre-tax loss of $2.3 billion associated with the divested Marcellus Shale upstream assets, driven by the loss on sale. For the three and nine months ended September 30, 2016 , our consolidated statements of operations include a pre-tax loss of $70 million and $237 million , respectively, associated with the divested Marcellus Shale upstream assets. Production from the Marcellus Shale upstream assets averaged 393 MMcfe/d and 413 MMcfe/d for the three and six months ended June 30, 2017. With the closing of the sale, we recorded a decrease in net proved reserves of approximately 241 MMBoe, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves as of June 30, 2017. Marcellus Shale CONE Gathering Divestiture On May 18, 2017, we announced the signing of a definitive agreement to divest an affiliate that holds the 50% interest in CONE Gathering, LLC (CONE Gathering) and 21.7 million common and subordinated limited partnership units in CONE Midstream Partners LP (NYSE:CNNX) (CONE Midstream), for total cash consideration of $765 million . CONE Gathering owns the general partner of CONE Midstream, and the limited partnership units represent a 33.5% ownership interest in CONE Midstream. CONE Midstream constructs, owns and operates natural gas gathering and other midstream energy assets in support of Marcellus Shale activities. In connection with the execution of the definitive agreement to divest the affiliate noted above, the other 50% owner of CONE Gathering filed suit to enjoin the transaction. A bench trial was concluded on October 20, 2017 and we are awaiting a decision from the court. We believe that the court will decide in our favor. However, given the pendency of the matter and the possibility of appeal, our ability to close the transaction as originally contemplated is uncertain at this time. We are committed to exiting the Marcellus Shale play, and going forward, our midstream efforts are primarily focused on Noble Midstream Partners, supporting our DJ Basin and Delaware Basin growth areas. We believe that classification of our investment in CONE Gathering as assets held for sale as of September 30, 2017 remains appropriate. Assets Held for Sale At September 30, 2017 , assets held for sale was primarily related to $173 million for our investment in CONE Gathering. Other US Onshore Properties We conducted the following transactions: • Onshore US Divestitures In third quarter 2017, we received proceeds of $24 million resulting from the sale of certain other onshore US properties and the remaining consideration associated with the Greeley Crescent divestiture (defined below) in the DJ Basin. • Delaware Basin Acquisition In first quarter 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million , approximately $246 million of which was allocated to undeveloped leasehold cost. The acquisition included seven producing wells, of which four are operated by us. Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million . Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo provides services across our development areas in the DJ Basin, including crude oil and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area. The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand. Advantage Acquisition On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50 /50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed $67 million of cash to the joint venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. Noble Midstream Partners serves as the operator of the Advantage Pipeline system, which includes a 70 -mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150,000 barrels per day of shipping capacity (expandable to over 200,000 barrels per day) and 490,000 barrels of storage capacity. 2016 Asset Transactions During the first nine months of 2016, we engaged in the following asset transactions. US Onshore Properties We entered into the following transactions: • Bowdoin Divestiture We closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43 million , and recognized a $23 million loss on sale; • Onshore US Divestitures We sold certain other US onshore properties, generating net proceeds of $20 million , which were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss; • Greeley Crescent Divestiture We entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped interests covering approximately 33,100 net acres in the Greeley Crescent (Greeley Crescent divestiture) area of the DJ Basin for $505 million , subject to customary closing adjustments. We received proceeds of $486 million during second quarter 2016, which were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss. In third quarter 2017, we closed the sale of the remaining properties and received proceeds of $5 million ; and • Acreage Exchange Agreement We entered into an acreage exchange agreement receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area, located southwest of Wells Ranch, with no recognition of gain or loss. Cyprus Project (Offshore Cyprus) In first quarter 2017, we received the remaining $40 million consideration for the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery. Proceeds received, including $131 million in first quarter 2016, were applied to the Cyprus project asset with no gain or loss recognized. Offshore Israel Assets In first quarter 2016, we closed the divestment of our 47% interest in the Alon A and Alon C licenses, which include the Karish and Tanin fields, for a total sales price of $73 million ( $67 million for asset consideration and $6 million for cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | 5. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil, natural gas and NGL pricing. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of September 30, 2017 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2H17 (1) Call Option (2) NYMEX WTI 3,000 $ — $ — $ — $ — $ 60.12 2H17 (1) Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 64.00 2017 Three-Way Collars NYMEX WTI 24,000 — — 39.08 47.71 61.20 2017 Two-Way Collars NYMEX WTI 10,804 — — — 40.80 52.72 2017 Swaps NYMEX WTI 4,293 — 50.84 — — — 2017 Call Option (2) NYMEX WTI 3,000 — — — — 57.00 2017 Three-Way Collars ICE Brent 2,000 — — 43.00 50.00 63.15 2017 Three-Way Collars Dated Brent 2,000 — — 35.00 45.00 66.33 2018 Three-Way Collars NYMEX WTI 10,000 — — 45.50 52.50 69.09 2018 Three-Way Collars Dated Brent 3,000 — — 40.00 50.00 70.41 2018 Swaptions (3) NYMEX WTI 3,000 — 56.10 — — — 2018 Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 59.50 2018 Two-Way Collars ICE Brent 2,000 — — — 50.00 55.25 2018 Basis Swap (4) 8,000 (0.78 ) — — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swap (4) 12,000 (1.01 ) — — — — (1) We have entered into contracts for portions of 2017 resulting in the difference in hedged volumes for the full year. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. (4) We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts. As of September 30, 2017 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2017 Three-Way Collars NYMEX HH 110,000 $ — $ 2.58 $ 2.93 $ 3.65 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 120,000 — 2.50 2.88 3.65 2018 Swaptions (1) NYMEX HH 30,000 3.36 — — — (1) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments September 30, December 31, September 30, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 7 Current Assets $ — Current Liabilities $ 4 Current Liabilities $ 102 Noncurrent Assets 5 Noncurrent Assets — Noncurrent Liabilities 2 Noncurrent Liabilities 14 Total $ 12 $ — $ 6 $ 116 The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (4 ) $ (119 ) $ (20 ) $ (395 ) Natural Gas — (13 ) 2 (59 ) Total Cash Received in Settlement of Commodity Derivative Instruments (4 ) (132 ) (18 ) (454 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 27 80 (64 ) 441 Natural Gas (1 ) (3 ) (63 ) 66 Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 26 77 (127 ) 507 Loss (Gain) on Commodity Derivative Instruments Crude Oil 23 (39 ) (84 ) 46 Natural Gas (1 ) (16 ) (61 ) 7 Total Loss (Gain) on Commodity Derivative Instruments $ 22 $ (55 ) $ (145 ) $ 53 |
Debt
Debt | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Debt | 6. Debt Debt consists of the following: September 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ 275 2.27 % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 200 2.45 % — — % Term Loan Facility, due January 6, 2019 550 2.45 % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % Senior Notes, due March 1, 2019 (1) — — % 1,000 8.25 % Senior Notes, due May 1, 2021 379 5.625 % 379 5.625 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 (1) 600 3.85 % — — % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 (1) 500 4.95 % — — % Other Senior Notes and Debentures (2) 110 6.93 % 110 6.93 % Capital Lease and Other Obligations (3) 290 — % 375 — % Total 7,604 7,114 Unamortized Discount (25 ) (23 ) Unamortized Premium 14 17 Unamortized Debt Issuance Costs (41 ) (34 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,552 7,074 Less Amounts Due Within One Year Capital Lease Obligations (65 ) (63 ) Long-Term Debt Due After One Year $ 7,487 $ 7,011 (1) In third quarter 2017, we redeemed all our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047. (2) Includes $ 18 million of Senior Notes due June 1, 2022, $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 6.93% . (3) The reduction includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $44 million of capital lease principal payments. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies . Revolving Credit Facility Our Credit Agreement, as amended, provides for a $ 4 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating. During second quarter 2017, we borrowed $ 1.3 billion to fund the cash portion of the Clayton Williams Energy Acquisition consideration, redeem assumed Clayton Williams Energy long-term debt, pay associated make-whole premiums, pay related fees and expenses associated with the transaction and to fund other general corporate expenditures. We repaid all of the respective outstanding borrowings associated with the transaction during second quarter 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash generated by the Noble Midstream Partners private placement of limited partner units and Noble Midstream Services borrowings. As of September 30, 2017, $275 million was outstanding under our Revolving Credit Facility, which was utilized for general corporate purposes and for funding of our capital development program. Noble Midstream Services Revolving Credit Facility In 2016, Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility) which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00% ; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. As of September 30, 2017, $200 million was outstanding under the Noble Midstream Services Revolving Credit Facility which was used to partially fund second quarter 2017 acquisitions. See Note 4. Acquisitions and Divestitures . Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million , both of which are reflected as a reduction of long-term debt and are amortized over the life of the facility. Proceeds of $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1.0 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our consolidated statements of operations. Leviathan Term Loan Agreement On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion , of which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel. Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios. Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period. The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries. Term Loan Agreement and Completed Tender Offers In 2016, we entered into a term loan agreement (Term Loan Facility) which provides for a three -year term loan facility for a principal amount of $ 1.4 billion. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5% , and (iii) LIBOR plus 1.0% , plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) LIBOR plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in our merger with Rosetta Resources Inc. in 2015. As a result, we recognized a gain of $80 million in first quarter 2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. As of September 30, 2017 , $ 550 million was outstanding under the facility. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, are as follows: (millions) Debt Principal Payments October - December 2017 $ — 2018 — 2019 550 2020 — 2021 1,379 Thereafter 4,910 Total $ 6,839 |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements and Disclosures | 7. Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities . Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above . Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) September 30, 2017 Financial Assets Mutual Fund Investments $ 70 $ — $ — $ — $ 70 Commodity Derivative Instruments — 16 — (4 ) 12 Financial Liabilities Commodity Derivative Instruments — (10 ) — 4 (6 ) Portion of Deferred Compensation Liability Measured at Fair Value (89 ) — — — (89 ) Stock Based Compensation Liability Measured at Fair Value (11 ) — — — — (11 ) December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — (9 ) (1) Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. (2) Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. (3) Level 3 measurements are fair value measurements which use unobservable inputs. (4) Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities such as inventory, oil and gas properties and assets held for sale are measured at fair value on a nonrecurring basis in our consolidated balance sheets. For the nine months ended September 30, 2017 and 2016, we had no adjustments in fair value related to these items. Other items measured at fair value on a nonrecurring basis are discussed below. Marcellus Shale Firm Transportation Liability As of September 30, 2017, we had a $39 million liability representing the discounted present value of our remaining obligation under a firm transportation contract. See Note 12. Commitments and Contingencies . Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy. Our Term Loan Facility and Revolving Credit Facility, along with the Noble Midstream Services Revolving Credit Facility, are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt . Fair value information regarding our debt is as follows: September 30, 2017 December 31, 2016 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,314 $ 7,715 $ 6,739 $ 7,112 (1) Excludes unamortized discount, premium, debt issuance costs and capital lease obligations. |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | 9 Months Ended |
Sep. 30, 2017 | |
Extractive Industries [Abstract] | |
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost. Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Nine Months Ended September 30, 2017 Capitalized Exploratory Well Costs, December 31, 2016 $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 10 Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1) (203 ) Capitalized Exploratory Well Costs, September 30, 2017 $ 575 (1) Amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel. During second quarter 2017, we recorded Leviathan field proved undeveloped reserves of 551 MMBoe, net. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 11 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1) 564 699 Balance at September 30, 2017 $ 575 $ 768 (1) The decrease from December 31, 2016 is attributable to the reclassification of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells. Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves, including proved undeveloped reserves, become attributable to the property as a result of our exploration and development activities. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective leases or licenses. As of September 30, 2017 , we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $3 billion , including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Resources Inc. acquisition in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. The remaining balance of undeveloped leasehold costs as of September 30, 2017 included $56 million related to Gulf of Mexico unproved properties and $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review. During the first nine months of 2017, we completed geological evaluations of certain Gulf of Mexico leases and licenses associated with other international unproved properties and determined that several should be relinquished or exited. As a result, we recognized $33 million and $51 million of undeveloped leasehold impairment expense for the three and nine months ended September 30, 2017 , respectively. Of these amounts, $31 million and $49 million for the respective periods are attributable to our Gulf of Mexico leases. These expenses are recorded in exploration expense in the consolidated statements of operations. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 9. Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Nine Months Ended September 30, (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 83 5 Liabilities Settled (53 ) (87 ) Revision of Estimate (56 ) 4 Accretion Expense (1) 35 37 Asset Retirement Obligations, Ending Balance $ 944 $ 948 (1) Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations. For the Nine Months Ended September 30, 2017 Liabilities incurred include $58 million related to the Clayton Williams Energy Acquisition and $25 million primarily for other US onshore wells and facilities placed into service. Liabilities settled include $37 million related to abandonment of onshore US properties, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $4 million related to other offshore international and US properties. Revisions of estimates relate to decreases in cost and timing estimates of $42 million associated with the North Sea abandonment project and $29 million for US onshore and Gulf of Mexico, partially offset by an increase of $15 million for West Africa. For the Nine Months Ended September 30, 2016 Liabilities incurred were due to new wells and facilities for onshore US. Liabilities settled primarily related to Gulf of Mexico and onshore US property abandonments. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 10. Income Taxes The income tax provision (benefit) consists of the following: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Current (1) $ 22 $ 148 $ 71 $ 213 Deferred (115 ) (285 ) (988 ) (699 ) Total Income Tax Benefit $ (93 ) $ (137 ) $ (917 ) $ (486 ) Effective Tax Rate 44.7 % 48.9 % 36.9 % 39.5 % (1) Current income taxes are attributable to our operations in Israel and Equatorial Guinea. Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR) to current year earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the three and nine months ended September 30, 2017 varied as compared with the three and nine months ended September 30, 2016 primarily due to a smaller prior year increase to the deferred tax liability recorded on unrepatriated earnings combined with a larger prior year discrete tax benefit driven by a tax rate change in a foreign jurisdiction. In addition, the significant increase in the deferred income tax benefit for the nine months ended September 30, 2017 is primarily due to the loss recorded for the Marcellus Shale upstream divestiture during second quarter 2017. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014 , Israel – 2015 and Equatorial Guinea – 2012 . Deferred Tax Assets We currently forecast that our US federal income tax net operating loss (NOL) carryforwards will be substantial at year end 2017. Included in the resulting deferred tax assets are acquired deferred tax assets associated with net operating losses of the Clayton Williams Energy Acquisition in 2017 and with the Rosetta Resources Inc. acquisition in 2015. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the associated tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies, as well as current and forecasted business economics in the oil and gas industry. Based on the level of our historical taxable income and projections for future taxable income, we currently believe it is more likely than not that we will realize the benefits of these NOL carryforwards. However, the amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards forecasted for year end 2017 of approximately $181 million at September 30, 2017 and $242 million at December 31, 2016. The decrease was attributable to the offset of the valuation allowance against the net operating loss in a jurisdiction in which we are no longer active. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | 11. Segment Information During second quarter 2017 , as a result of the strategic changes in our US onshore portfolio, we established our Midstream business as a new reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream Partners, additional US onshore midstream assets and US onshore equity method investments, was previously reported within the United States reportable segment. As a result, as of June 30, 2017, we now have five reportable segments, United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada and New Ventures); and Midstream. The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. The Corporate reportable segment incurs expenses related to debt, headquarters depreciation and corporate general and administrative cost. Prior period amounts are presented on a comparable basis. Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l (1) United States Intersegment Eliminations and Other Corporate Three Months Ended September 30, 2017 Oil, NGL and Gas Sales from Third Parties $ 907 $ 696 $ 141 $ 70 $ — $ — $ — $ — Income from Equity Method Investees and Other 53 — — 33 — 20 — — Intersegment Revenues — — — — — 72 (72 ) — Total Revenues 960 696 141 103 — 92 (72 ) — Lease Operating Expense 151 118 9 25 — — (1 ) — Production and Ad Valorem Taxes 36 35 — — — 1 — — Gathering, Transportation and Processing Expense 93 129 — — — 20 (56 ) — Total Production Expense 280 282 9 25 — 21 (57 ) — DD&A 523 442 18 41 1 10 (1 ) 12 Loss on Marcellus Shale Upstream Divestiture 4 4 — — — — — — Clayton Williams Energy Acquisition Expenses 4 4 — — — — — — Loss on Commodity Derivative Instruments 22 16 — 6 — — — — (Loss) Income Before Income Taxes (2) (208 ) (115 ) 109 24 23 58 (12 ) (295 ) Three Months Ended September 30, 2016 Oil, NGL and Gas Sales from Third Parties $ 882 $ 638 $ 150 $ 94 $ — $ — $ — $ — Income from Equity Method Investees and Other 28 — — 19 — 9 — — Intersegment Revenues — — — — — 57 (57 ) Total Revenues 910 638 150 113 — 66 (57 ) — Lease Operating Expense 131 106 8 22 — — (5 ) — Production and Ad Valorem Taxes 30 29 — — — 1 — — Gathering, Transportation and Processing Expense 121 144 — — — 11 (34 ) — Total Production Expense 282 279 8 22 — 12 (39 ) — DD&A 621 536 22 46 1 5 — 11 Loss on Commodity Derivative Instruments (55 ) (48 ) — (7 ) — — — — (Loss) Income Before Income Taxes (2) (280 ) (255 ) 135 48 (33 ) 47 (18 ) (204 ) Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l (1) United States Intersegment Eliminations and Other Corporate Nine Months Ended September 30, 2017 Oil, NGL and Gas Sales from Third Parties $ 2,918 $ 2,246 $ 406 $ 266 $ — $ — $ — $ — Income from Equity Method Investees and Other 137 — — 84 — 53 — — Intersegment Revenues — — — — — 198 (198 ) — Total Revenues 3,055 2,246 406 350 — 251 (198 ) — Lease Operating Expense 414 332 23 65 — — (6 ) — Production and Ad Valorem Taxes 119 117 — — — 2 — — Gathering, Transportation and Processing Expense 333 416 — — — 53 (136 ) — Total Production Expense 866 865 23 65 — 55 (142 ) — DD&A 1,554 1,326 58 114 4 20 (2 ) 34 Loss on Marcellus Shale Upstream Divestiture 2,326 2,326 — — — — — — Clayton Williams Energy Acquisition Expenses 98 98 — — — — — — Gain on Commodity Derivative Instruments (145 ) (138 ) — (7 ) — — — — (Loss) Income Before Income Taxes (2) (2,483 ) (2,433 ) 316 162 11 165 (47 ) (657 ) Nine Months Ended September 30, 2016 Oil, NGL and Gas Sales from Third Parties $ 2,411 $ 1,705 $ 407 $ 299 $ — $ — $ — $ — Income from Equity Method Investees and Other 70 — — 31 — 39 — — Intersegment Revenues — — — — — 143 (143 ) — Total Revenues 2,481 1,705 407 330 — 182 (143 ) — Lease Operating Expense 412 324 25 75 — — (12 ) — Production and Ad Valorem Taxes 73 70 — — — 3 — — Gathering, Transportation and Processing Expense 354 417 — — — 31 (94 ) — Total Production Expense 839 811 25 75 — 34 (106 ) — DD&A 1,859 1,599 62 150 4 14 — 30 Loss on Commodity Derivative Instruments 53 45 — 8 — — — — (Loss) Income Before Income Taxes (2) (1,231 ) (1,076 ) 290 74 (98 ) 126 (37 ) (510 ) September 30, 2017 Goodwill (3) $ 1,295 $ 1,295 $ — $ — $ — $ — $ — $ — Total Assets 21,649 16,287 2,681 1,265 108 1,158 (142 ) 292 December 31, 2016 Total Assets 21,011 16,153 2,233 1,479 89 851 (98 ) 304 (1) Income before income taxes for the three and nine months ended September 30, 2017 primarily relates to the North Sea remediation project revision. See Note 2. Basis of Presentation and Note 9. Asset Retirement Obligations . (2) The intersegment eliminations related to (loss) income before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the upstream business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (3) Goodwill in our United States reportable segment is associated with our Texas reporting unit. See Note 2. Basis of Presentation . |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 12. Commitments and Contingencies Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. Marcellus Shale Firm Transportation Contracts In connection with the Marcellus Shale upstream divestiture, we reduced our firm transportation commitment through transfer of certain contracts to the acquirer. We retained certain other firm transportation contracts representing a total financial commitment of approximately $1.6 billion , undiscounted, primarily with remaining contract terms of 15 years. Of this amount, approximately $627 million , undiscounted, relates to two pipeline projects which are currently under construction and targeted to be placed in service mid-to-late fourth quarter 2017. We are in negotiations with third parties for the commercialization and permanent assignment or release of a portion of our capacity under these contracts which would reduce our undiscounted financial commitment. As these pipeline projects become commercially available to us and our commitment begins, we will evaluate our position, commercialization activities and ability to utilize retained capacity. If we determine that we will not utilize a portion, or all, of the contracted and retained pipeline capacity, we will accrue a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations. At this time, we are unable to predict with certainty the outcome of our commercialization activities, our ability to utilize retained capacity and the timing of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with these two pipeline projects. See Note 2. Basis of Presentation . The remaining commitments relate to two additional pipeline projects that are targeted to be placed in service late 2018, one of which has not yet been approved by the FERC. We continue to monitor and assess the status of these pipeline projects, including regulatory approval and construction progress, and are evaluating commercialization options. We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts. These financial commitments are included in the table below consistent with expected future cash payments associated with the underlying agreements. See Note 4. Acquisitions and Divestitures . Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property and have entered into numerous long-term contracts for gathering, processing and transportation services. Minimum commitments have been updated to give effect to the Clayton Williams Energy Acquisition, the Marcellus Shale upstream divestiture, as well as commitments related to Leviathan development activities, and consist of the following as of September 30, 2017: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations (1) Operating Lease Obligations Capital Lease Obligations (2) Total October - December 2017 $ 136 $ 53 $ 12 $ 20 $ 221 2018 425 247 43 74 789 2019 148 276 32 45 501 2020 26 249 32 42 349 2021 7 213 32 29 281 2022 and Thereafter 36 1,499 189 145 1,869 Total $ 778 $ 2,537 $ 340 $ 355 $ 4,010 (1) Includes approximately $1.6 billion of future cash payments related to retained Marcellus Shale firm transportation contracts. See discussion above. (2) Annual lease payments, net to our interest, exclude regular maintenance and operating costs. See Note 6. Debt . Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the court on June 2, 2015. The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities and to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree. Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. In May 2017, we reached a final resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Presentation | Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2017 and December 31, 2016 and for the three and nine months ended September 30, 2017 and 2016 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is materially consistent with comprehensive income or loss. In Note 11. Segment Information , we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . |
Consolidation | Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (NYSE: NBLX) (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. |
Goodwill | Goodwill As of September 30, 2017 , our consolidated balance sheet includes goodwill of $1.3 billion . This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017 , and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit. See Note 3. Clayton Williams Energy Acquisition . Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for newly issued accounting guidance regarding future goodwill impairment testing. We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill. Certain negative indicators included the current commodity price environment (driven by several macroeconomic factors) coupled with onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as our current and future drilling and development plans for our Texas assets, synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability. Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware basin. Having assessed the totality of such events and circumstances described above, we determined that while there exist certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with the conduct of Step 1 of the impairment test as part of our annual review. As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, by approximately 6% and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017. If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. |
Exit Costs | Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Our exit costs in 2017 relate primarily to estimated costs associated with a retained Marcellus Shale firm transportation contract, for which we accrued an exit liability at June 30, 2017. The recognition and fair value estimation of a liability requires that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies . |
Estimates | Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Reserves Estimates Estimated quantities of crude oil, natural gas and natural gas liquids (NGL) reserves are the most significant of our estimates. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available engineering and geoscience information and also interpretation of the provided data. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition. We continue to evaluate the impact of the ASU on our accounting policies, internal controls, and consolidated financial statements and related disclosures. We are performing a review of contracts for each of our revenue streams and developing accounting policies to address the provisions of the ASU. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. The ASU also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any, on the presentation of our future revenues and expenses under this gross-versus-net presentation guidance. Based upon assessments performed to date, we do not expect the ASU to have a material effect on the timing of revenue recognition or our financial position. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach with a cumulative adjustment to retained earnings as necessary. Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We do not believe adoption of ASU 2017-09 will have a material impact on our financial statements. We will adopt the new standard on the effective date of January 1, 2018. Business Combinations: Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of transactions to be accounted for as business transactions, which take more time and cost more to analyze than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition is not impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption on January 1, 2018. Statement of Cash Flows: Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash , which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. We will adopt the new standard on the effective date of January 1, 2018. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments , to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. We will adopt the new standard on the effective date of January 1, 2018. Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. At this time, we cannot reasonably estimate the financial impact this ASU will have on our financial statements; however, we believe adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. We will adopt the new standard on the effective date of January 1, 2019. Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt. Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. We will adopt the new standard on the effective date of January 1, 2020. |
Basis of Presentation (Tables)
Basis of Presentation (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Statement of Operations Information | Other statements of operations information is as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Production Expense Lease Operating Expense $ 151 $ 131 $ 414 $ 412 Production and Ad Valorem Taxes 36 30 119 73 Gathering, Transportation and Processing Expense (1) 93 121 333 354 Total $ 280 $ 282 $ 866 $ 839 Exploration Expense Leasehold Impairment and Amortization (2) $ 33 $ 96 $ 51 $ 127 Dry Hole Cost (3) 2 5 2 105 Seismic, Geological and Geophysical 7 15 20 47 Staff Expense 11 15 40 53 Other 11 (6 ) 23 44 Total $ 64 $ 125 $ 136 $ 376 Loss on Marcellus Shale Upstream Divestiture (4) Loss on Sale $ — $ — $ 2,270 $ — Firm Transportation Commitment (5) — — 41 — Other (6) 4 — 15 — Total $ 4 $ — $ 2,326 $ — Other Operating Expense, Net (7) Marketing Expense (1) (8) $ 6 $ 12 $ 39 $ 39 Clayton Williams Energy Acquisition Expenses (9) 4 — 98 — Loss on Asset Due to Terminated Contract (10) — — — 47 North Sea Remediation Project Revision (11) (42 ) — (42 ) — Other, Net 17 25 37 41 Total $ (15 ) $ 37 $ 132 $ 127 (1) Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the three and nine months ended September 30, 2017 , these costs totaled $12 million and $17 million , respectively. For the three and nine months ended September 30, 2016 , these costs totaled $8 million and $19 million , respectively, and have been reclassified from marketing expense to conform to the current presentation. (2) See Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) For the nine months ended September 30, 2016, amount related primarily to the Silvergate exploratory well, Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel. (4) See Note 4. Acquisitions and Divestitures . (5) Amount represents expense related to an unutilized firm transportation commitment associated with a Marcellus Shale firm transportation contract. See Note 12. Commitments and Contingencies . (6) Amount includes costs for legal and advisory services and employee severance charges. (7) (Gain)/Loss on debt extinguishment was historically presented as a component of other operating expense, net in our consolidated statements of operations. Beginning with third quarter 2017, we have changed our presentation to reflect these as a separate line item within other expense (income) below operating loss. The prior periods have been reclassified to conform to that presentation. (8) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (9) See Note 3. Clayton Williams Energy Acquisition . (10) Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance. (11) See Note 9. Asset Retirement Obligations |
Balance Sheet Information Table | Other balance sheet information is as follows: (millions) September 30, December 31, Accounts Receivable, Net Commodity Sales $ 403 $ 403 Joint Interest Billings 183 106 Proceeds Receivable (1) — 40 Other 106 86 Allowance for Doubtful Accounts (17 ) (20 ) Total $ 675 $ 615 Other Current Assets Inventories, Materials and Supplies $ 61 $ 71 Inventories, Crude Oil 17 18 Assets Held for Sale (2) 180 18 Restricted Cash (3) — 30 Prepaid Expenses and Other Current Assets 45 23 Total $ 303 $ 160 Other Noncurrent Assets Equity Method Investments $ 286 $ 400 Mutual Fund Investments 70 71 Other Assets, Noncurrent 60 37 Total $ 416 $ 508 Other Current Liabilities Production and Ad Valorem Taxes $ 118 $ 115 Commodity Derivative Liabilities 4 102 Income Taxes Payable 13 53 Asset Retirement Obligations (4) 50 160 Interest Payable 82 76 Current Portion of Capital Lease Obligations 65 63 Foreign Sales Tax Payable 29 14 Compensation and Benefits Payable 87 110 Theoretical Withdrawal Premium 25 18 Other Liabilities, Current (5) 26 31 Total $ 499 $ 742 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 216 $ 218 Asset Retirement Obligations (4) 894 775 Marcellus Shale Firm Transportation Commitment (6) 31 — Production and Ad Valorem Taxes 49 47 Other Liabilities, Noncurrent 55 63 Total $ 1,245 $ 1,103 (1) Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017. See Note 4. Acquisitions and Divestitures . (2) Balance at September 30, 2017 primarily includes our equity investment in CONE Gathering, LLC. See Note 4. Acquisitions and Divestitures . (3) Balance at December 31, 2016 represented amount held in escrow for the purchase of certain Delaware Basin properties. The transaction closed in first quarter 2017. See Note 4. Acquisitions and Divestitures . (4) Reclassification from current to noncurrent is driven primarily by a change in expected timing of abandonment activities in the Gulf of Mexico. See Note 9. Asset Retirement Obligations . (5) Balance at September 30, 2017 includes $8 million associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies . (6) See Note 12. Commitments and Contingencies . |
Clayton Williams Energy Acqui22
Clayton Williams Energy Acquisition (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Schedule of Business Acquisitions, by Acquisition | The following table sets forth our preliminary purchase price allocation: (millions, except per share amounts) Fair Value of Common Stock Issued $ 1,876 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,513 Plus Liabilities Assumed by Noble Energy: Accounts Payable 67 Other Current Liabilities 38 Long-Term Deferred Tax Liability 520 Long-Term Debt 595 Asset Retirement Obligations 58 Total Purchase Price Plus Liabilities Assumed $ 3,791 The fair value of Clayton Williams Energy's identifiable assets is as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 63 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Cost 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 58 Other Noncurrent Assets 13 Implied Goodwill 1,295 Total Asset Value $ 3,791 |
Business Acquisition, Pro Forma Information | The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the three and nine months ended September 30, 2017 were adjusted to exclude acquisition-related costs of $4 million and $98 million , respectively, incurred by Noble Energy and $23 million , incurred by Clayton Williams Energy in second quarter 2017. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. Three Months Ended September 30, Nine Months Ended September 30, (millions, except per share amounts) 2017 (1) 2016 2017 2016 Revenues $ 960 $ 964 $ 3,102 $ 2,605 Net Loss and Comprehensive Loss Attributable to Noble Energy (133 ) (193 ) (1,561 ) (860 ) Net Loss Attributable to Noble Energy per Common Share Basic and Diluted $ (0.27 ) $ (0.40 ) $ (3.21 ) $ (1.77 ) (1) Adjusted for $4 million acquisition-related costs, net of 35% tax, incurred during third quarter 2017. |
Derivative Instruments and He23
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Unsettled Derivative Instruments | As of September 30, 2017 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2H17 (1) Call Option (2) NYMEX WTI 3,000 $ — $ — $ — $ — $ 60.12 2H17 (1) Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 64.00 2017 Three-Way Collars NYMEX WTI 24,000 — — 39.08 47.71 61.20 2017 Two-Way Collars NYMEX WTI 10,804 — — — 40.80 52.72 2017 Swaps NYMEX WTI 4,293 — 50.84 — — — 2017 Call Option (2) NYMEX WTI 3,000 — — — — 57.00 2017 Three-Way Collars ICE Brent 2,000 — — 43.00 50.00 63.15 2017 Three-Way Collars Dated Brent 2,000 — — 35.00 45.00 66.33 2018 Three-Way Collars NYMEX WTI 10,000 — — 45.50 52.50 69.09 2018 Three-Way Collars Dated Brent 3,000 — — 40.00 50.00 70.41 2018 Swaptions (3) NYMEX WTI 3,000 — 56.10 — — — 2018 Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 59.50 2018 Two-Way Collars ICE Brent 2,000 — — — 50.00 55.25 2018 Basis Swap (4) 8,000 (0.78 ) — — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swap (4) 12,000 (1.01 ) — — — — (1) We have entered into contracts for portions of 2017 resulting in the difference in hedged volumes for the full year. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. (4) We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts. As of September 30, 2017 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2017 Three-Way Collars NYMEX HH 110,000 $ — $ 2.58 $ 2.93 $ 3.65 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 120,000 — 2.50 2.88 3.65 2018 Swaptions (1) NYMEX HH 30,000 3.36 — — — (1) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. |
Fair Value of Derivative Instruments | The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments September 30, December 31, September 30, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 7 Current Assets $ — Current Liabilities $ 4 Current Liabilities $ 102 Noncurrent Assets 5 Noncurrent Assets — Noncurrent Liabilities 2 Noncurrent Liabilities 14 Total $ 12 $ — $ 6 $ 116 |
Derivative Instruments, (Gain) Loss | The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (4 ) $ (119 ) $ (20 ) $ (395 ) Natural Gas — (13 ) 2 (59 ) Total Cash Received in Settlement of Commodity Derivative Instruments (4 ) (132 ) (18 ) (454 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 27 80 (64 ) 441 Natural Gas (1 ) (3 ) (63 ) 66 Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 26 77 (127 ) 507 Loss (Gain) on Commodity Derivative Instruments Crude Oil 23 (39 ) (84 ) 46 Natural Gas (1 ) (16 ) (61 ) 7 Total Loss (Gain) on Commodity Derivative Instruments $ 22 $ (55 ) $ (145 ) $ 53 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consists of the following: September 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ 275 2.27 % $ — — % Noble Midstream Services Revolving Credit Facility, due September 20, 2021 200 2.45 % — — % Term Loan Facility, due January 6, 2019 550 2.45 % 550 2.01 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % Senior Notes, due March 1, 2019 (1) — — % 1,000 8.25 % Senior Notes, due May 1, 2021 379 5.625 % 379 5.625 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 (1) 600 3.85 % — — % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 (1) 500 4.95 % — — % Other Senior Notes and Debentures (2) 110 6.93 % 110 6.93 % Capital Lease and Other Obligations (3) 290 — % 375 — % Total 7,604 7,114 Unamortized Discount (25 ) (23 ) Unamortized Premium 14 17 Unamortized Debt Issuance Costs (41 ) (34 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 7,552 7,074 Less Amounts Due Within One Year Capital Lease Obligations (65 ) (63 ) Long-Term Debt Due After One Year $ 7,487 $ 7,011 (1) In third quarter 2017, we redeemed all our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047. (2) Includes $ 18 million of Senior Notes due June 1, 2022, $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 6.93% . (3) The reduction includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $44 million of capital lease principal payments. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies . |
Annual debt maturities | Annual maturities of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, are as follows: (millions) Debt Principal Payments October - December 2017 $ — 2018 — 2019 550 2020 — 2021 1,379 Thereafter 4,910 Total $ 6,839 |
Fair Value Measurements and D25
Fair Value Measurements and Disclosures (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement (millions) September 30, 2017 Financial Assets Mutual Fund Investments $ 70 $ — $ — $ — $ 70 Commodity Derivative Instruments — 16 — (4 ) 12 Financial Liabilities Commodity Derivative Instruments — (10 ) — 4 (6 ) Portion of Deferred Compensation Liability Measured at Fair Value (89 ) — — — (89 ) Stock Based Compensation Liability Measured at Fair Value (11 ) — — — — (11 ) December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — (9 ) (1) Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. (2) Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. (3) Level 3 measurements are fair value measurements which use unobservable inputs. (4) Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. |
Additional fair value disclosures | Fair value information regarding our debt is as follows: September 30, 2017 December 31, 2016 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 7,314 $ 7,715 $ 6,739 $ 7,112 (1) Excludes unamortized discount, premium, debt issuance costs and capital lease obligations. |
Capitalized Exploratory Well 26
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Extractive Industries [Abstract] | |
Changes in Capitalized Exploratory Well Costs | Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Nine Months Ended September 30, 2017 Capitalized Exploratory Well Costs, December 31, 2016 $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 10 Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1) (203 ) Capitalized Exploratory Well Costs, September 30, 2017 $ 575 (1) Amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel. During second quarter 2017, we recorded Leviathan field proved undeveloped reserves of 551 MMBoe, net. |
Aging of Capitalized Well Costs | The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) September 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 11 $ 69 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1) 564 699 Balance at September 30, 2017 $ 575 $ 768 (1) The decrease from December 31, 2016 is attributable to the reclassification of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Changes in Asset Retirement Obligations | Changes in ARO are as follows: Nine Months Ended September 30, (millions) 2017 2016 Asset Retirement Obligations, Beginning Balance $ 935 $ 989 Liabilities Incurred 83 5 Liabilities Settled (53 ) (87 ) Revision of Estimate (56 ) 4 Accretion Expense (1) 35 37 Asset Retirement Obligations, Ending Balance $ 944 $ 948 (1) Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Provision (Benefit) | The income tax provision (benefit) consists of the following: Three Months Ended September 30, Nine Months Ended September 30, (millions) 2017 2016 2017 2016 Current (1) $ 22 $ 148 $ 71 $ 213 Deferred (115 ) (285 ) (988 ) (699 ) Total Income Tax Benefit $ (93 ) $ (137 ) $ (917 ) $ (486 ) Effective Tax Rate 44.7 % 48.9 % 36.9 % 39.5 % (1) Current income taxes are attributable to our operations in Israel and Equatorial Guinea. |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l (1) United States Intersegment Eliminations and Other Corporate Three Months Ended September 30, 2017 Oil, NGL and Gas Sales from Third Parties $ 907 $ 696 $ 141 $ 70 $ — $ — $ — $ — Income from Equity Method Investees and Other 53 — — 33 — 20 — — Intersegment Revenues — — — — — 72 (72 ) — Total Revenues 960 696 141 103 — 92 (72 ) — Lease Operating Expense 151 118 9 25 — — (1 ) — Production and Ad Valorem Taxes 36 35 — — — 1 — — Gathering, Transportation and Processing Expense 93 129 — — — 20 (56 ) — Total Production Expense 280 282 9 25 — 21 (57 ) — DD&A 523 442 18 41 1 10 (1 ) 12 Loss on Marcellus Shale Upstream Divestiture 4 4 — — — — — — Clayton Williams Energy Acquisition Expenses 4 4 — — — — — — Loss on Commodity Derivative Instruments 22 16 — 6 — — — — (Loss) Income Before Income Taxes (2) (208 ) (115 ) 109 24 23 58 (12 ) (295 ) Three Months Ended September 30, 2016 Oil, NGL and Gas Sales from Third Parties $ 882 $ 638 $ 150 $ 94 $ — $ — $ — $ — Income from Equity Method Investees and Other 28 — — 19 — 9 — — Intersegment Revenues — — — — — 57 (57 ) Total Revenues 910 638 150 113 — 66 (57 ) — Lease Operating Expense 131 106 8 22 — — (5 ) — Production and Ad Valorem Taxes 30 29 — — — 1 — — Gathering, Transportation and Processing Expense 121 144 — — — 11 (34 ) — Total Production Expense 282 279 8 22 — 12 (39 ) — DD&A 621 536 22 46 1 5 — 11 Loss on Commodity Derivative Instruments (55 ) (48 ) — (7 ) — — — — (Loss) Income Before Income Taxes (2) (280 ) (255 ) 135 48 (33 ) 47 (18 ) (204 ) Oil and Gas Exploration and Production Midstream (In millions) Consolidated United Eastern West Other Int'l (1) United States Intersegment Eliminations and Other Corporate Nine Months Ended September 30, 2017 Oil, NGL and Gas Sales from Third Parties $ 2,918 $ 2,246 $ 406 $ 266 $ — $ — $ — $ — Income from Equity Method Investees and Other 137 — — 84 — 53 — — Intersegment Revenues — — — — — 198 (198 ) — Total Revenues 3,055 2,246 406 350 — 251 (198 ) — Lease Operating Expense 414 332 23 65 — — (6 ) — Production and Ad Valorem Taxes 119 117 — — — 2 — — Gathering, Transportation and Processing Expense 333 416 — — — 53 (136 ) — Total Production Expense 866 865 23 65 — 55 (142 ) — DD&A 1,554 1,326 58 114 4 20 (2 ) 34 Loss on Marcellus Shale Upstream Divestiture 2,326 2,326 — — — — — — Clayton Williams Energy Acquisition Expenses 98 98 — — — — — — Gain on Commodity Derivative Instruments (145 ) (138 ) — (7 ) — — — — (Loss) Income Before Income Taxes (2) (2,483 ) (2,433 ) 316 162 11 165 (47 ) (657 ) Nine Months Ended September 30, 2016 Oil, NGL and Gas Sales from Third Parties $ 2,411 $ 1,705 $ 407 $ 299 $ — $ — $ — $ — Income from Equity Method Investees and Other 70 — — 31 — 39 — — Intersegment Revenues — — — — — 143 (143 ) — Total Revenues 2,481 1,705 407 330 — 182 (143 ) — Lease Operating Expense 412 324 25 75 — — (12 ) — Production and Ad Valorem Taxes 73 70 — — — 3 — — Gathering, Transportation and Processing Expense 354 417 — — — 31 (94 ) — Total Production Expense 839 811 25 75 — 34 (106 ) — DD&A 1,859 1,599 62 150 4 14 — 30 Loss on Commodity Derivative Instruments 53 45 — 8 — — — — (Loss) Income Before Income Taxes (2) (1,231 ) (1,076 ) 290 74 (98 ) 126 (37 ) (510 ) September 30, 2017 Goodwill (3) $ 1,295 $ 1,295 $ — $ — $ — $ — $ — $ — Total Assets 21,649 16,287 2,681 1,265 108 1,158 (142 ) 292 December 31, 2016 Total Assets 21,011 16,153 2,233 1,479 89 851 (98 ) 304 (1) Income before income taxes for the three and nine months ended September 30, 2017 primarily relates to the North Sea remediation project revision. See Note 2. Basis of Presentation and Note 9. Asset Retirement Obligations . (2) The intersegment eliminations related to (loss) income before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the upstream business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (3) Goodwill in our United States reportable segment is associated with our Texas reporting unit. See Note 2. Basis of Presentation . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments | Minimum commitments have been updated to give effect to the Clayton Williams Energy Acquisition, the Marcellus Shale upstream divestiture, as well as commitments related to Leviathan development activities, and consist of the following as of September 30, 2017: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations (1) Operating Lease Obligations Capital Lease Obligations (2) Total October - December 2017 $ 136 $ 53 $ 12 $ 20 $ 221 2018 425 247 43 74 789 2019 148 276 32 45 501 2020 26 249 32 42 349 2021 7 213 32 29 281 2022 and Thereafter 36 1,499 189 145 1,869 Total $ 778 $ 2,537 $ 340 $ 355 $ 4,010 (1) Includes approximately $1.6 billion of future cash payments related to retained Marcellus Shale firm transportation contracts. See discussion above. (2) Annual lease payments, net to our interest, exclude regular maintenance and operating costs. See Note 6. Debt . |
Basis of Presentation (Details)
Basis of Presentation (Details) $ in Millions | Jun. 30, 2017MMBoe | Sep. 30, 2017USD ($)MMBoe | Jun. 30, 2017USD ($)MMBoe | Sep. 30, 2016USD ($) | Jun. 30, 2017MMBoe | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Apr. 24, 2017USD ($) | Dec. 31, 2016USD ($) |
Goodwill | $ 1,295 | $ 1,295 | $ 0 | ||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 551 | 551 | 551 | ||||||
Production Expense | |||||||||
Lease Operating Expense | 151 | $ 131 | 414 | $ 412 | |||||
Production and Ad Valorem Taxes | 36 | 30 | 119 | 73 | |||||
Gathering, Transportation and Processing Expense | 93 | 121 | 333 | 354 | |||||
Total | 280 | 282 | 866 | 839 | |||||
Exploration Expense | |||||||||
Leasehold Impairment and Amortization | 33 | 96 | 51 | 127 | |||||
Dry Hole Cost | 2 | 5 | 2 | 105 | |||||
Seismic, Geological and Geophysical | 7 | 15 | 20 | 47 | |||||
Staff Expense | 11 | 15 | 40 | 53 | |||||
Other | 11 | (6) | 23 | 44 | |||||
Total | 64 | 125 | 136 | 376 | |||||
Loss on Sale | 0 | 0 | 2,270 | 0 | |||||
Firm transportation liability | 0 | 0 | 41 | 0 | |||||
Other | 4 | 0 | 15 | 0 | |||||
Total | 4 | 0 | 2,326 | 0 | |||||
Other Operating Expense, Net (7) | |||||||||
Marketing Expense | 6 | 12 | 39 | 39 | |||||
Clayton Williams Energy Acquisition Expenses | 4 | 0 | 98 | 0 | |||||
Loss on Asset Due to Terminated Contract | 0 | 0 | 0 | 47 | |||||
North Sea Remediation Project Revision | (42) | 0 | (42) | 0 | |||||
Other, Net | 17 | 25 | 37 | 41 | |||||
Total | (15) | 37 | 132 | 127 | |||||
Gathering, Transportation and Processing Expense | 93 | 121 | 333 | 354 | |||||
Accounts Receivable, Net | |||||||||
Commodity Sales | 403 | 403 | 403 | ||||||
Joint Interest Billings | 183 | 183 | 106 | ||||||
Proceeds Receivable | 0 | 0 | 40 | ||||||
Other | 106 | 106 | 86 | ||||||
Allowance for Doubtful Accounts | (17) | (17) | (20) | ||||||
Total | 675 | 675 | 615 | ||||||
Other Current Assets | |||||||||
Inventories, Materials and Supplies | 61 | 61 | 71 | ||||||
Inventories, Crude Oil | 17 | 17 | 18 | ||||||
Assets Held for Sale | 180 | 180 | 18 | ||||||
Restricted Cash | 0 | 0 | 30 | ||||||
Prepaid Expenses and Other Current Assets | 45 | 45 | 23 | ||||||
Total | 303 | 303 | 160 | ||||||
Other Noncurrent Assets | |||||||||
Equity Method Investments | 286 | 286 | 400 | ||||||
Mutual Fund Investments | 70 | 70 | 71 | ||||||
Other Assets, Noncurrent | 60 | 60 | 37 | ||||||
Total | 416 | 416 | 508 | ||||||
Other Current Liabilities | |||||||||
Production and Ad Valorem Taxes | 118 | 118 | 115 | ||||||
Commodity Derivative Liabilities | 4 | 4 | 102 | ||||||
Income Taxes Payable | 13 | 13 | 53 | ||||||
Asset Retirement Obligations | 50 | 50 | 160 | ||||||
Interest Payable | 82 | 82 | 76 | ||||||
Current Portion of Capital Lease Obligations | 65 | 65 | 63 | ||||||
Foreign Sales Tax Payable | 29 | 29 | 14 | ||||||
Compensation and Benefits Payable | 87 | 87 | 110 | ||||||
Theoretical Withdrawal Premium | 25 | 25 | 18 | ||||||
Other Liabilities, Current | 26 | 26 | 31 | ||||||
Total | 499 | 499 | 742 | ||||||
Other Noncurrent Liabilities | |||||||||
Deferred Compensation Liabilities | 216 | 216 | 218 | ||||||
Asset Retirement Obligations | 894 | 894 | 775 | ||||||
Marcellus Shale Firm Transportation Commitment | 31 | 31 | 0 | ||||||
Production and Ad Valorem Taxes | 49 | 49 | 47 | ||||||
Other Liabilities, Noncurrent | 55 | 55 | 63 | ||||||
Total | 1,245 | 1,245 | $ 1,103 | ||||||
Percentage of divestiture farmed out | 35.00% | ||||||||
Firm transportation liability | $ 39 | 39 | |||||||
Leviathan | |||||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 551 | 551 | 551 | ||||||
Tamar Field | |||||||||
Increase (decrease) in net proved reserves (MMBOEs) | MMBoe | 48 | ||||||||
Marcellus Shale | |||||||||
Proved developed and undeveloped reserves, decreased reserves from divestiture (MMBOEs) | MMBoe | 241 | ||||||||
Decrease in proved developed reserves (MMBOEs) | MMBoe | 190 | ||||||||
Decrease in undeveloped reserves (MMBOEs) | MMBoe | 51 | ||||||||
Clayton Williams Energy | |||||||||
Goodwill | $ 1,300 | 1,300 | $ 1,295 | ||||||
Other Operating Expense, Net (7) | |||||||||
Clayton Williams Energy Acquisition Expenses | $ 23 | 64 | |||||||
Clayton Williams Energy | Delaware Basin | |||||||||
Increase (decrease) in net proved reserves (MMBOEs) | MMBoe | 86 | ||||||||
Proved developed reserves (MMBOEs) | MMBoe | 17 | 17 | 17 | ||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 69 | 69 | 69 | ||||||
Scenario, Previously Reported | |||||||||
Other Operating Expense, Net (7) | |||||||||
Gathering, Transportation and Processing Expense | 12 | $ 8 | 17 | $ 19 | |||||
Other Current Liabilities | |||||||||
Other Noncurrent Liabilities | |||||||||
Firm transportation liability | $ 8 | $ 8 | |||||||
Texas Reporting Unit | |||||||||
Percentage of fair value in excess of carrying amount | 6.00% | 6.00% |
Clayton Williams Energy Acqui32
Clayton Williams Energy Acquisition (Details) $ / shares in Units, shares in Thousands, a in Thousands, $ in Millions | Apr. 24, 2017USD ($)a$ / sharesshares | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($)MMBoe | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($)MMBoe | Sep. 30, 2017USD ($)ashares | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) |
Business Acquisition [Line Items] | |||||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 551 | 551 | |||||||
Cash consideration | $ 616 | $ 0 | |||||||
Acquisition related costs | $ 4 | $ 0 | 98 | $ 0 | |||||
Goodwill | 1,295 | $ 1,295 | 1,295 | $ 0 | |||||
Clayton Williams Energy | |||||||||
Business Acquisition [Line Items] | |||||||||
Area acquired (acres) | a | 118 | ||||||||
Shares exchange in acquisition (shares) | shares | 56,000 | ||||||||
Equity consideration | $ 1,876 | ||||||||
Cash consideration | 637 | ||||||||
Consideration | $ 2,513 | ||||||||
Stock price ($ per share) | $ / shares | $ 34.17 | ||||||||
Credit facility draw | $ 1,300 | $ 1,300 | |||||||
Acquisition related costs | $ 23 | 64 | |||||||
Noncash share compensation | $ 34 | ||||||||
Treasury shares received in acquisition | shares | 720 | ||||||||
Increase to treasury stock | $ 25 | ||||||||
Debt assumed | $ 595 | ||||||||
Goodwill | $ 1,295 | 1,300 | 1,300 | 1,300 | |||||
Pro forma revenue | 56 | ||||||||
Pro forma loss | $ 14 | ||||||||
Clayton Williams Energy | |||||||||
Business Acquisition [Line Items] | |||||||||
Acquisition related costs | $ 4 | $ 98 | |||||||
Tax rate | 35.00% | ||||||||
Delaware Basin | Clayton Williams Energy | |||||||||
Business Acquisition [Line Items] | |||||||||
Area acquired (acres) | a | 71 | ||||||||
Increase (MMBOEs) | MMBoe | 86 | ||||||||
Proved developed reserves (MMBOEs) | MMBoe | 17 | 17 | |||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 69 | 69 | |||||||
Permian | Clayton Williams Energy | |||||||||
Business Acquisition [Line Items] | |||||||||
Area acquired (acres) | a | 100 | ||||||||
TEXAS | Clayton Williams Energy | |||||||||
Business Acquisition [Line Items] | |||||||||
Area acquired (acres) | a | 64 |
Clayton Williams Energy Acqui33
Clayton Williams Energy Acquisition - Tables (Details) - USD ($) $ / shares in Units, $ in Millions | Apr. 24, 2017 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 |
Business Acquisition [Line Items] | ||||||
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | $ 616 | $ 0 | ||||
Goodwill | $ 1,295 | 1,295 | $ 0 | |||
Clayton Williams Energy | ||||||
Business Acquisition [Line Items] | ||||||
Fair Value of Common Stock Issued | $ 1,876 | |||||
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 | |||||
Total Purchase Price | 2,513 | |||||
Accounts Payable | 67 | |||||
Other Current Liabilities | 38 | |||||
Long-Term Deferred Tax Liability | 520 | |||||
Long-Term Debt | 595 | |||||
Asset Retirement Obligations | 58 | |||||
Total Purchase Price Plus Liabilities Assumed | 3,791 | |||||
Cash and Cash Equivalents | 21 | |||||
Other Current Assets | 63 | |||||
Proved Reserves | 722 | |||||
Undeveloped Leasehold Cost | 1,571 | |||||
Gathering and Processing Assets | 48 | |||||
Asset Retirement Costs | 58 | |||||
Other Noncurrent Assets | 13 | |||||
Goodwill | 1,295 | 1,300 | 1,300 | |||
Total Asset Value | $ 3,791 | |||||
Revenues | 960 | $ 964 | 3,102 | 2,605 | ||
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ (133) | $ (193) | $ (1,561) | $ (860) | ||
Net Loss Attributable to Noble Energy per Common Share - Basic and Diluted ($ per share) | $ (0.27) | $ (0.40) | $ (3.21) | $ (1.77) |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) bbl / d in Thousands, bbl in Thousands, $ in Millions | Jun. 30, 2017MMBoe | Jun. 28, 2017USD ($)$ / MMBTUpayment | Jun. 26, 2017USD ($)ashares | May 18, 2017USD ($)shares | Apr. 03, 2017USD ($)bbl / dmibbl | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($)MMcf / dMMBoe | Mar. 31, 2017USD ($)well | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Jun. 30, 2017MMcf / dMMBoe | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($)a | Jun. 27, 2017USD ($) | Dec. 31, 2016USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proceeds | $ 1,028 | $ 0 | ||||||||||||||
Loss on Marcellus Shale Upstream Divestiture | $ 4 | $ 0 | 2,326 | 0 | ||||||||||||
Firm transportation liability | 0 | 0 | 41 | 0 | ||||||||||||
Income (loss) before income taxes | 208 | 280 | 2,483 | 1,231 | ||||||||||||
Proved undeveloped reserves (MMBOEs) | MMBoe | (551) | (551) | (551) | |||||||||||||
Proceeds from divestiture of Onshore US | 129 | 786 | ||||||||||||||
Cash consideration | 616 | 0 | ||||||||||||||
Borrowings | 245 | 0 | ||||||||||||||
Gain (loss) on sale | 0 | 0 | (2,270) | 0 | ||||||||||||
Proceeds receivable | 0 | 0 | $ 40 | |||||||||||||
Percentage of divestiture farmed out | 35.00% | |||||||||||||||
Marcellus Shale | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Total transaction value | $ 1,200 | |||||||||||||||
Proceeds | 1,000 | |||||||||||||||
Contingent adjustment | $ 100 | |||||||||||||||
Number of payments | payment | 3 | |||||||||||||||
Individual payment | $ 33.3 | |||||||||||||||
Contingent consideration ($ per MMBtu) | $ / MMBTU | 3.30 | |||||||||||||||
Loss on Marcellus Shale Upstream Divestiture | $ 2,300 | |||||||||||||||
Gain (loss), net of tax | $ 1,500 | |||||||||||||||
Assets | $ 3,400 | |||||||||||||||
Income (loss) before income taxes | 70 | 2,300 | 237 | |||||||||||||
Natural gas production per day (MMcf per day) | MMcf / d | 393 | 413 | ||||||||||||||
CONE Gathering LLC | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Total transaction value | $ 765 | |||||||||||||||
Assets | 173 | $ 173 | ||||||||||||||
Ownership | 50.00% | |||||||||||||||
Ownership interest | 33.50% | |||||||||||||||
Onshore US | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proceeds | 20 | |||||||||||||||
Proceeds from divestiture of Onshore US | 24 | |||||||||||||||
Delaware Basin | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Consideration | $ 301 | |||||||||||||||
Allocated to undeveloped leasehold | $ 246 | |||||||||||||||
Number of wells | well | 7 | |||||||||||||||
Number of wells operated by company | well | 4 | |||||||||||||||
Leaseholds and Leasehold Improvements | Marcellus Shale | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Assets | $ 883 | |||||||||||||||
Subsidiaries | Blanco River and Colorado River DevCos | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Consideration | $ 270 | |||||||||||||||
Dedications area for oil, gas and water gathering services (in acres) | a | 111,000 | |||||||||||||||
Cash consideration | $ 245 | |||||||||||||||
Shares exchange in acquisition (shares) | shares | 562,430 | |||||||||||||||
Proceeds from equity | $ 138 | |||||||||||||||
Borrowings | $ 90 | |||||||||||||||
Noble Midstream Partners LP | Blanco River DevCo | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Additional voting interests acquired in limited partnership | 15.00% | |||||||||||||||
Equity interest in acquiree | 40.00% | |||||||||||||||
Noble Midstream Partners LP | Colorado River DevCo | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Additional voting interests acquired in limited partnership | 20.00% | |||||||||||||||
Noble Midstream Partners LP | Blanco River and Colorado River DevCos | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Consideration | $ 270 | |||||||||||||||
Noble Midstream Partners LP | Advantage Pipeline | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Ownership | 50.00% | |||||||||||||||
Consideration | $ 133 | |||||||||||||||
Length of pipeline (miles) | mi | 70 | |||||||||||||||
Shipping capacity (barrels per day) | bbl / d | 150 | |||||||||||||||
Storage capacity (barrels per day) | bbl | 490 | |||||||||||||||
Advantage Joint Venture | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Payments to acquire joint venture | $ 66.8 | |||||||||||||||
Maximum | Noble Midstream Partners LP | Advantage Pipeline | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Shipping capacity (barrels per day) | bbl / d | 200 | |||||||||||||||
Member Units | CONE Gathering LLC | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Equity owned (units) | shares | 21,700,000 | |||||||||||||||
Marcellus Shale | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proved developed and undeveloped reserves, decreased reserves from divestiture (MMBOEs) | MMBoe | 241 | |||||||||||||||
Decrease in proved developed reserves (MMBOEs) | MMBoe | 190 | |||||||||||||||
Decrease in undeveloped reserves (MMBOEs) | MMBoe | 51 | |||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | MONTANA | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proceeds | 43 | |||||||||||||||
Gain (loss) on sale | $ (23) | |||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Producing and Undeveloped Net Acres in the DJ Basin | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proceeds | $ 5 | $ 486 | ||||||||||||||
Purchase and sales agreement, area (acres) | a | 33,100 | |||||||||||||||
Purchase and sales agreement, consideration | $ 505 | $ 505 | ||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Cyprus Block 12 | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Proceeds receivable | $ 40 | |||||||||||||||
Proceeds received from farm-out agreement | $ 131 | |||||||||||||||
Percentage of divestiture farmed out | 35.00% | |||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Alon A And Alon C | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Total transaction value | $ 73 | |||||||||||||||
Contingent adjustment | 6 | |||||||||||||||
Assets | $ 67 | |||||||||||||||
Percentage of divestiture farmed out | 47.00% | |||||||||||||||
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Exchange | Wells Ranch Development Area | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Land exchanged (acres) | a | 11,700 | |||||||||||||||
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Exchange | Bronco Development Area | ||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||
Purchase and sales agreement, area (acres) | a | 13,500 |
Derivative Instruments and He35
Derivative Instruments and Hedging Activities (Details) | Sep. 30, 2017bbl / d$ / shares$ / bbl |
Crude Oil Contract | Call Option - NYMEX WTI Second Half of 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Three Way Collars - ICE Brent Second Half of 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 5,000 |
Crude Oil Contract | Three Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 24,000 |
Crude Oil Contract | Two Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 10,804 |
Crude Oil Contract | Swaps - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 4,293 |
Crude Oil Contract | Call Option - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Three Way Collars - ICE Brent 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 2,000 |
Crude Oil Contract | Three Way Collars - Dated Brent 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 2,000 |
Crude Oil Contract | Three Way Collars - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 10,000 |
Crude Oil Contract | Three Way Collars - Dated Brent 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Swaptions - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Three Way Collars - ICE Brent 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 5,000 |
Crude Oil Contract | Two Way Collars - ICE Brent 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 2,000 |
Crude Oil Contract | Basic Swap 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 8,000 |
Crude Oil Contract | Three Way Collar - ICE Brent 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Basic Swap 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 12,000 |
Natural Gas Contract | Three Way Collars - NYMEX HH 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 110,000 |
Weighted Average Fixed Price ($ per bbl) | 0 |
Weighted Average Short Put Price ($ per bbl) | 2.58 |
Weighted Average Floor Price ($ per bbl) | 2.93 |
Weighted Average Ceiling Price ($ per bbl) | 3.65 |
Natural Gas Contract | Two Way Collars - NYMEX HH 2017 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 70,000 |
Weighted Average Fixed Price ($ per bbl) | 0 |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 2.93 |
Weighted Average Ceiling Price ($ per bbl) | 3.32 |
Natural Gas Contract | Three Way Collars - NYMEX HH 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 120,000 |
Weighted Average Fixed Price ($ per bbl) | 0 |
Weighted Average Short Put Price ($ per bbl) | 2.50 |
Weighted Average Floor Price ($ per bbl) | 2.88 |
Weighted Average Ceiling Price ($ per bbl) | 3.65 |
Natural Gas Contract | Swaptions - NYMEX HH 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 30,000 |
Weighted Average Fixed Price ($ per bbl) | 3.36 |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 0 |
Weighted Average Ceiling Price ($ per bbl) | 0 |
Swaps | Crude Oil Contract | Swaps - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 50.84 |
Swaps | Crude Oil Contract | Swaptions - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 56.10 |
Swaps | Crude Oil Contract | Basic Swap 2018 | |
Derivative [Line Items] | |
Weighted Average Differential ($ per bbl) | $ / shares | $ (0.78) |
Swaps | Crude Oil Contract | Basic Swap 2019 | |
Derivative [Line Items] | |
Weighted Average Differential ($ per bbl) | $ / shares | $ (1.01) |
Collars | Crude Oil Contract | Call Option - NYMEX WTI Second Half of 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 0 |
Weighted Average Ceiling Price ($ per bbl) | 60.12 |
Collars | Crude Oil Contract | Three Way Collars - ICE Brent Second Half of 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 64 |
Collars | Crude Oil Contract | Three Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 39.08 |
Weighted Average Floor Price ($ per bbl) | 47.71 |
Weighted Average Ceiling Price ($ per bbl) | 61.20 |
Collars | Crude Oil Contract | Two Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 40.80 |
Weighted Average Ceiling Price ($ per bbl) | 52.72 |
Collars | Crude Oil Contract | Call Option - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 0 |
Weighted Average Ceiling Price ($ per bbl) | 57 |
Collars | Crude Oil Contract | Three Way Collars - ICE Brent 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 63.15 |
Collars | Crude Oil Contract | Three Way Collars - Dated Brent 2017 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 35 |
Weighted Average Floor Price ($ per bbl) | 45 |
Weighted Average Ceiling Price ($ per bbl) | 66.33 |
Collars | Crude Oil Contract | Three Way Collars - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 45.50 |
Weighted Average Floor Price ($ per bbl) | 52.50 |
Weighted Average Ceiling Price ($ per bbl) | 69.09 |
Collars | Crude Oil Contract | Three Way Collars - Dated Brent 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 40 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 70.41 |
Collars | Crude Oil Contract | Three Way Collars - ICE Brent 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 59.50 |
Collars | Crude Oil Contract | Two Way Collars - ICE Brent 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 0 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 55.25 |
Collars | Crude Oil Contract | Three Way Collar - ICE Brent 2019 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 64.07 |
Derivative Instruments and He36
Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | $ 12 | $ 12 | $ 0 | ||
Derivative Liability, Fair Value | 6 | 6 | 116 | ||
Total Cash Received in Settlement of Commodity Derivative Instruments | (4) | $ (132) | (18) | $ (454) | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 26 | 77 | (127) | 507 | |
Total Loss (Gain) on Commodity Derivative Instruments | 22 | (55) | (145) | 53 | |
Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 7 | 7 | 0 | ||
Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 4 | 4 | 102 | ||
Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 5 | 5 | 0 | ||
Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 2 | 2 | $ 14 | ||
Crude Oil | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash Received in Settlement of Commodity Derivative Instruments | (4) | (119) | (20) | (395) | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 27 | 80 | (64) | 441 | |
Total Loss (Gain) on Commodity Derivative Instruments | 23 | (39) | (84) | 46 | |
Natural Gas | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash Received in Settlement of Commodity Derivative Instruments | 0 | (13) | 2 | (59) | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | (1) | (3) | (63) | 66 | |
Total Loss (Gain) on Commodity Derivative Instruments | $ (1) | $ (16) | $ (61) | $ 7 |
Debt (Details)
Debt (Details) - USD ($) | Aug. 15, 2017 | Sep. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | Jun. 30, 2017 | Feb. 24, 2017 |
Debt Instrument [Line Items] | ||||||||||
Long-term Debt and Capital Lease Obligations, Including Current Maturities | $ 7,604,000,000 | $ 7,114,000,000 | $ 7,604,000,000 | $ 7,114,000,000 | ||||||
Unamortized Discount | (25,000,000) | (23,000,000) | (25,000,000) | (23,000,000) | ||||||
Unamortized Premium | 14,000,000 | 17,000,000 | 14,000,000 | 17,000,000 | ||||||
Unamortized Debt Issuance Costs | (41,000,000) | (34,000,000) | (41,000,000) | (34,000,000) | ||||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | 7,552,000,000 | 7,074,000,000 | 7,552,000,000 | 7,074,000,000 | ||||||
Capital Lease Obligations | (65,000,000) | (63,000,000) | (65,000,000) | (63,000,000) | ||||||
Long-Term Debt Due After One Year | 7,487,000,000 | 7,011,000,000 | 7,487,000,000 | 7,011,000,000 | ||||||
Proceeds from Issuance of Senior Notes, Net | 1,086,000,000 | $ 0 | ||||||||
Borrowings | 245,000,000 | 0 | ||||||||
Loss (Gain) on Extinguishment of Debt | 98,000,000 | $ 0 | 98,000,000 | (80,000,000) | ||||||
Repayments | 850,000,000 | $ 1,310,000,000 | $ 0 | |||||||
Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Unamortized Discount | $ (4,000,000) | |||||||||
Debt issuance costs, gross | 11,000,000 | |||||||||
Proceeds from Issuance of Senior Notes, Net | $ 1,100,000,000 | |||||||||
Loss on debt refinance | 98,000,000 | |||||||||
Noble Midstream | Line of Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | 350,000,000 | 350,000,000 | ||||||||
Noble Midstream | Line of Credit Facility | Federal Funds Effective Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 0.50% | |||||||||
Noble Midstream | Line of Credit Facility | London Interbank Offered Rate (LIBOR) | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 1.00% | |||||||||
Clayton Williams Energy | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility draw | $ 1,300,000,000 | |||||||||
Revolving Credit Facility, due August 27, 2020 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 275,000,000 | $ 0 | $ 275,000,000 | $ 0 | ||||||
Interest rate | 2.27% | 0.00% | 2.27% | 0.00% | ||||||
Maximum borrowing capacity | $ 4,000,000,000 | $ 4,000,000,000 | ||||||||
Credit facility fee rate basis points, minimum | 0.10% | 0.10% | ||||||||
Credit facility fee rate basis points, maximum | 0.25% | 0.25% | ||||||||
Credit facility interest rate, Eurodollar rate plus, minimum | 0.90% | 0.90% | ||||||||
Credit facility interest rate, Eurodollar rate plus, maximum | 1.50% | 1.50% | ||||||||
Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 200,000,000 | $ 0 | $ 200,000,000 | $ 0 | ||||||
Interest rate | 2.45% | 0.00% | 2.45% | 0.00% | ||||||
Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | Noble Midstream | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 200,000,000 | $ 200,000,000 | ||||||||
Term Loan Facility, due January 6, 2019 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 550,000,000 | $ 550,000,000 | $ 550,000,000 | $ 550,000,000 | ||||||
Interest rate | 2.45% | 2.01% | 2.45% | 2.01% | ||||||
Maximum borrowing capacity | $ 1,400,000,000 | $ 1,400,000,000 | ||||||||
Term Loan Facility, due January 6, 2019 | Line of Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility fee rate basis points, minimum | 0.10% | 0.10% | ||||||||
Credit facility fee rate basis points, maximum | 0.75% | 0.75% | ||||||||
Term | 3 years | |||||||||
Borrowings | $ 1,380,000,000 | |||||||||
Term Loan Facility, due January 6, 2019 | Line of Credit Facility | Federal Funds Effective Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 0.50% | |||||||||
Term Loan Facility, due January 6, 2019 | Line of Credit Facility | London Interbank Offered Rate (LIBOR) | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility interest rate, Eurodollar rate plus, minimum | 1.00% | 1.00% | ||||||||
Credit facility interest rate, Eurodollar rate plus, maximum | 1.75% | 1.75% | ||||||||
Debt instrument, variable rate | 1.00% | |||||||||
Term Loan Facility, due January 6, 2019 | Other Operating Income (Expense) | Line of Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Loss (Gain) on Extinguishment of Debt | $ (80,000,000) | |||||||||
Leviathan Term Loan Facility, due February 23, 2025 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 0 | $ 0 | $ 0 | $ 0 | ||||||
Interest rate | 0.00% | 0.00% | 0.00% | 0.00% | ||||||
Leviathan Term Loan Facility, due February 23, 2025 | Line of Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 1,000,000,000 | |||||||||
Credit facility draw | $ 625,000,000 | |||||||||
Maximum final balloon payment allowable | 35.00% | |||||||||
Commitment fee | 1.00% | |||||||||
Leviathan Term Loan Facility, due February 23, 2025 | Line of Credit Facility | LIBOR Prior to Production Startup | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 3.50% | |||||||||
Leviathan Term Loan Facility, due February 23, 2025 | Line of Credit Facility | LIBOR After Startup Prior to Two Years Before Maturity | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 3.25% | |||||||||
Leviathan Term Loan Facility, due February 23, 2025 | Line of Credit Facility | LIBOR Last Two Years Until Maturity | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, variable rate | 3.75% | |||||||||
Senior Notes, due March 1, 2019 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 0 | $ 1,000,000,000 | $ 0 | $ 1,000,000,000 | ||||||
Interest rate | 0.00% | 8.25% | 0.00% | 8.25% | ||||||
Senior Notes, due March 1, 2019 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate | 8.25% | |||||||||
Unamortized Premium | $ 96,000,000 | |||||||||
Debt instrument, face amount | $ 1,000,000,000 | |||||||||
Senior Notes, due May 1, 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 379,000,000 | $ 379,000,000 | $ 379,000,000 | $ 379,000,000 | ||||||
Interest rate | 5.625% | 5.625% | 5.625% | 5.625% | ||||||
Senior Notes, due December 15, 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | ||||||
Interest rate | 4.15% | 4.15% | 4.15% | 4.15% | ||||||
Senior Notes due October 15, 2023 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 100,000,000 | $ 100,000,000 | $ 100,000,000 | $ 100,000,000 | ||||||
Interest rate | 7.25% | 7.25% | 7.25% | 7.25% | ||||||
Senior Notes, due November 15, 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 650,000,000 | $ 650,000,000 | $ 650,000,000 | $ 650,000,000 | ||||||
Interest rate | 3.90% | 3.90% | 3.90% | 3.90% | ||||||
Senior Notes, due April 1, 2027 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 250,000,000 | $ 250,000,000 | $ 250,000,000 | $ 250,000,000 | ||||||
Interest rate | 8.00% | 8.00% | 8.00% | 8.00% | ||||||
Senior Notes due January 15, 2028 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 600,000,000 | $ 0 | $ 600,000,000 | $ 0 | ||||||
Interest rate | 3.85% | 0.00% | 3.85% | 0.00% | ||||||
Senior Notes due January 15, 2028 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate | 3.85% | |||||||||
Debt instrument, face amount | $ 600,000,000 | |||||||||
Senior Notes, due March 1, 2041 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | ||||||
Interest rate | 6.00% | 6.00% | 6.00% | 6.00% | ||||||
Senior Notes, due November 15, 2043 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | ||||||
Interest rate | 5.25% | 5.25% | 5.25% | 5.25% | ||||||
Senior Notes, due November 15, 2044 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | ||||||
Interest rate | 5.05% | 5.05% | 5.05% | 5.05% | ||||||
Senior Notes due August 15, 2047 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 500,000,000 | $ 0 | $ 500,000,000 | $ 0 | ||||||
Interest rate | 4.95% | 0.00% | 4.95% | 0.00% | ||||||
Senior Notes due August 15, 2047 | Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate | 4.95% | |||||||||
Debt instrument, face amount | $ 500,000,000 | |||||||||
Other Senior Notes and Debentures (2) | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 110,000,000 | $ 110,000,000 | $ 110,000,000 | $ 110,000,000 | ||||||
Interest rate | 6.93% | 6.93% | 6.93% | 6.93% | ||||||
Capital Lease and Other Obligations | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate | 0.00% | 0.00% | 0.00% | 0.00% | ||||||
Capital Lease Obligations | $ 290,000,000 | $ 375,000,000 | $ 290,000,000 | $ 375,000,000 | ||||||
Senior Notes, due June 1, 2022 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | 18,000,000 | 18,000,000 | ||||||||
Senior Notes, due June 1, 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | 8,000,000 | 8,000,000 | ||||||||
Senior Debentures due August 1, 2097 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 84,000,000 | $ 84,000,000 | ||||||||
Senior Notes due June 1, 2022, June 1, 2024 and Senior Debentures due August 1, 2097 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt, Weighted Average Interest Rate | 6.93% | 6.93% | ||||||||
Marcellus Shale | Capital Lease and Other Obligations | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt | $ 41,000,000 | $ 41,000,000 | ||||||||
Capital lease principal payments | $ 44,000,000 |
Debt - Annual Debt Maturities (
Debt - Annual Debt Maturities (Details) $ in Millions | Sep. 30, 2017USD ($) |
Debt Disclosure [Abstract] | |
October - December 2017 | $ 0 |
2,018 | 0 |
2,019 | 550 |
2,020 | 0 |
2,021 | 1,379 |
Thereafter | 4,910 |
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | $ 6,839 |
Fair Value Measurements and D39
Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Recurring Basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Financial Assets | ||
Mutual Fund Investments | $ 70 | $ 71 |
Commodity Derivative Instruments | 12 | 0 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (6) | (116) |
Portion of Deferred Compensation Liability Measured at Fair Value | (89) | (88) |
Stock Based Compensation Liability Measured at Fair Value | (11) | (9) |
Quoted Prices in Active Markets (Level 1) | ||
Financial Assets | ||
Mutual Fund Investments | 70 | 71 |
Commodity Derivative Instruments | 0 | 0 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 0 | 0 |
Portion of Deferred Compensation Liability Measured at Fair Value | (89) | (88) |
Stock Based Compensation Liability Measured at Fair Value | (11) | (9) |
Significant Other Observable Inputs (Level 2) | ||
Financial Assets | ||
Mutual Fund Investments | 0 | 0 |
Commodity Derivative Instruments | 16 | 5 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (10) | (121) |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 |
Significant Unobservable Inputs (Level 3) | ||
Financial Assets | ||
Mutual Fund Investments | 0 | 0 |
Commodity Derivative Instruments | 0 | |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 0 | 0 |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 |
Scenario, Adjustment | ||
Financial Assets | ||
Mutual Fund Investments | 0 | 0 |
Commodity Derivative Instruments | (4) | (5) |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 4 | 5 |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | $ 0 | $ 0 |
Fair Value Measurements and D40
Fair Value Measurements and Disclosures - Narrative (Details) $ in Millions | Sep. 30, 2017USD ($) |
Fair Value Disclosures [Abstract] | |
Firm transportation liability | $ 39 |
Fair Value Measurements and D41
Fair Value Measurements and Disclosures (Details 3) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Net | $ 7,314 | $ 6,739 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Net | $ 7,715 | $ 7,112 |
Capitalized Exploratory Well 42
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2017USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017MMBoe | Apr. 24, 2017USD ($) | Dec. 31, 2016USD ($) | |
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized Exploratory Well Costs, December 31, 2016 | $ 768 | ||||||
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 10 | ||||||
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves | (203) | ||||||
Capitalized Exploratory Well Costs, September 30, 2017 | $ 575 | 575 | |||||
Proved undeveloped reserves (MMBOEs) | MMBoe | 551 | ||||||
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ 11 | $ 69 | |||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 564 | 699 | |||||
Balance at End of Period | 575 | 768 | $ 575 | $ 768 | |||
Capitalized undeveloped leasehold cost | 3,000 | ||||||
Impairment of undeveloped oil and gas leasehold | 33 | 51 | $ 81 | ||||
Clayton Williams Energy | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized undeveloped leasehold cost | 1,600 | ||||||
Onshore US | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized undeveloped leasehold cost | 1,100 | ||||||
Eagle Ford | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized undeveloped leasehold cost | 149 | ||||||
Deepwater Gulf of Mexico | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized undeveloped leasehold cost | 56 | ||||||
Other Int'l | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Capitalized undeveloped leasehold cost | 53 | ||||||
Gulf of Mexico and Falkland Islands | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Impairment of undeveloped oil and gas leasehold | $ 31 | $ 49 | |||||
Clayton Williams Energy | |||||||
Capitalized Exploratory Well Costs [Roll Forward] | |||||||
Properties acquired | $ 1,571 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligations, Beginning Balance | $ 935 | $ 989 |
Liabilities Incurred | 83 | 5 |
Liabilities Settled | (53) | (87) |
Revision of Estimate | (56) | 4 |
Accretion Expense | 35 | 37 |
Asset Retirement Obligations, Ending Balance | 944 | $ 948 |
Onshore US | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 25 | |
West Africa | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | 15 | |
Clayton Williams Energy | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 58 | |
Onshore US | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Settled | (37) | |
Marcellus Shale | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Settled | (12) | |
Other Offshore International and US Properties | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Settled | (4) | |
North Sea | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | 42 | |
US Onshore and Gulf of Mexico | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | $ 29 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||||
Current | $ 22 | $ 148 | $ 71 | $ 213 | |
Deferred | (115) | (285) | (988) | (699) | |
Total Income Tax Benefit | $ (93) | $ (137) | $ (917) | $ (486) | |
Effective Tax Rate | 44.70% | 48.90% | 36.90% | 39.50% | |
Foreign Loss Carryforward | |||||
Operating Loss Carryforwards [Line Items] | |||||
Deferred tax assets, valuation allowance | $ 181 | $ 181 | $ 242 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($)Operating_Segment | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | |
Segment Reporting [Abstract] | |||||
Number of operating segments | Operating_Segment | 5 | ||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | $ 907 | $ 882 | $ 2,918 | $ 2,411 | |
Income from Equity Method Investees and Other | 53 | 28 | 137 | 70 | |
Intersegment Revenues | 0 | 0 | 0 | 0 | |
Total | 960 | 910 | 3,055 | 2,481 | |
Lease Operating Expense | 151 | 131 | 414 | 412 | |
Production and Ad Valorem Taxes | 36 | 30 | 119 | 73 | |
Gathering, Transportation and Processing Expense | 93 | 121 | 333 | 354 | |
Total | 280 | 282 | 866 | 839 | |
DD&A | 523 | 621 | 1,554 | 1,859 | |
Loss on Marcellus Shale Upstream Divestiture | 4 | 0 | 2,326 | 0 | |
Clayton Williams Energy Acquisition Expenses | 4 | 0 | 98 | 0 | |
Loss on Commodity Derivative Instruments | 22 | (55) | (145) | 53 | |
(Loss) Income Before Income Taxes | (208) | (280) | (2,483) | (1,231) | |
Goodwill | 1,295 | 1,295 | $ 0 | ||
Total Assets | 21,649 | 21,649 | 21,011 | ||
Intersegment Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 0 | 0 | 0 | 0 | |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 | |
Intersegment Revenues | (72) | (57) | (198) | (143) | |
Total | (72) | (57) | (198) | (143) | |
Lease Operating Expense | (1) | (5) | (6) | (12) | |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 | |
Gathering, Transportation and Processing Expense | (56) | (34) | (136) | (94) | |
Total | (57) | (39) | (142) | (106) | |
DD&A | (1) | 0 | (2) | 0 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 | |
(Loss) Income Before Income Taxes | (12) | (18) | (47) | (37) | |
Goodwill | 0 | 0 | |||
Total Assets | (142) | (142) | (98) | ||
Corporate | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 0 | 0 | 0 | 0 | |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 | |
Intersegment Revenues | 0 | 0 | 0 | ||
Total | 0 | 0 | 0 | 0 | |
Lease Operating Expense | 0 | 0 | 0 | 0 | |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 | |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 | |
Total | 0 | 0 | 0 | 0 | |
DD&A | 12 | 11 | 34 | 30 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 | |
(Loss) Income Before Income Taxes | (295) | (204) | (657) | (510) | |
Goodwill | 0 | 0 | |||
Total Assets | 292 | 292 | 304 | ||
United States | Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 696 | 638 | 2,246 | 1,705 | |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 | |
Intersegment Revenues | 0 | 0 | 0 | 0 | |
Total | 696 | 638 | 2,246 | 1,705 | |
Lease Operating Expense | 118 | 106 | 332 | 324 | |
Production and Ad Valorem Taxes | 35 | 29 | 117 | 70 | |
Gathering, Transportation and Processing Expense | 129 | 144 | 416 | 417 | |
Total | 282 | 279 | 865 | 811 | |
DD&A | 442 | 536 | 1,326 | 1,599 | |
Loss on Marcellus Shale Upstream Divestiture | 4 | 2,326 | |||
Clayton Williams Energy Acquisition Expenses | 4 | 98 | |||
Loss on Commodity Derivative Instruments | 16 | (48) | (138) | 45 | |
(Loss) Income Before Income Taxes | (115) | (255) | (2,433) | (1,076) | |
Goodwill | 1,295 | 1,295 | |||
Total Assets | 16,287 | 16,287 | 16,153 | ||
United States | Noble Midstream | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 0 | 0 | 0 | 0 | |
Income from Equity Method Investees and Other | 20 | 9 | 53 | 39 | |
Intersegment Revenues | 72 | 57 | 198 | 143 | |
Total | 92 | 66 | 251 | 182 | |
Lease Operating Expense | 0 | 0 | 0 | 0 | |
Production and Ad Valorem Taxes | 1 | 1 | 2 | 3 | |
Gathering, Transportation and Processing Expense | 20 | 11 | 53 | 31 | |
Total | 21 | 12 | 55 | 34 | |
DD&A | 10 | 5 | 20 | 14 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 | |
(Loss) Income Before Income Taxes | 58 | 47 | 165 | 126 | |
Goodwill | 0 | 0 | |||
Total Assets | 1,158 | 1,158 | 851 | ||
Eastern Mediter- ranean | Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 141 | 150 | 406 | 407 | |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 | |
Intersegment Revenues | 0 | 0 | 0 | 0 | |
Total | 141 | 150 | 406 | 407 | |
Lease Operating Expense | 9 | 8 | 23 | 25 | |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 | |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 | |
Total | 9 | 8 | 23 | 25 | |
DD&A | 18 | 22 | 58 | 62 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 | |
(Loss) Income Before Income Taxes | 109 | 135 | 316 | 290 | |
Goodwill | 0 | 0 | |||
Total Assets | 2,681 | 2,681 | 2,233 | ||
West Africa | Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 70 | 94 | 266 | 299 | |
Income from Equity Method Investees and Other | 33 | 19 | 84 | 31 | |
Intersegment Revenues | 0 | 0 | 0 | 0 | |
Total | 103 | 113 | 350 | 330 | |
Lease Operating Expense | 25 | 22 | 65 | 75 | |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 | |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 | |
Total | 25 | 22 | 65 | 75 | |
DD&A | 41 | 46 | 114 | 150 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 6 | (7) | (7) | 8 | |
(Loss) Income Before Income Taxes | 24 | 48 | 162 | 74 | |
Goodwill | 0 | 0 | |||
Total Assets | 1,265 | 1,265 | 1,479 | ||
Other Int'l | Operating Segments | |||||
Segment Reporting Information [Line Items] | |||||
Oil, NGL and Gas Sales from Third Parties | 0 | 0 | 0 | 0 | |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 | |
Intersegment Revenues | 0 | 0 | 0 | 0 | |
Total | 0 | 0 | 0 | 0 | |
Lease Operating Expense | 0 | 0 | 0 | 0 | |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 | |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 | |
Total | 0 | 0 | 0 | 0 | |
DD&A | 1 | 1 | 4 | 4 | |
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | |||
Clayton Williams Energy Acquisition Expenses | 0 | 0 | |||
Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 | |
(Loss) Income Before Income Taxes | 23 | $ (33) | 11 | $ (98) | |
Goodwill | 0 | 0 | |||
Total Assets | $ 108 | $ 108 | $ 89 |
Commitments and Contingencies46
Commitments and Contingencies (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 24 Months Ended | |||
May 31, 2017 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2017 | |
Other Commitments [Line Items] | ||||||||
Firm transportation liability | $ 0 | $ 0 | $ (41,000) | $ 0 | ||||
October - December 2017 | 221,000 | 221,000 | ||||||
2,018 | 789,000 | 789,000 | ||||||
2,019 | 501,000 | 501,000 | ||||||
2,020 | 349,000 | 349,000 | ||||||
2,021 | 281,000 | 281,000 | ||||||
2022 and Thereafter | 1,869,000 | 1,869,000 | ||||||
Other Commitment | 4,010,000 | 4,010,000 | ||||||
Transportation Agreement Commitments | ||||||||
Other Commitments [Line Items] | ||||||||
Other Commitment | 1,600,000 | 1,600,000 | ||||||
Drilling, Equipment, and Purchase Obligations | ||||||||
Other Commitments [Line Items] | ||||||||
October - December 2017 | 136,000 | 136,000 | ||||||
2,018 | 425,000 | 425,000 | ||||||
2,019 | 148,000 | 148,000 | ||||||
2,020 | 26,000 | 26,000 | ||||||
2,021 | 7,000 | 7,000 | ||||||
2022 and Thereafter | 36,000 | 36,000 | ||||||
Other Commitment | 778,000 | 778,000 | ||||||
Transportation and Gathering Obligations | ||||||||
Other Commitments [Line Items] | ||||||||
October - December 2017 | 53,000 | 53,000 | ||||||
2,018 | 247,000 | 247,000 | ||||||
2,019 | 276,000 | 276,000 | ||||||
2,020 | 249,000 | 249,000 | ||||||
2,021 | 213,000 | 213,000 | ||||||
2022 and Thereafter | 1,499,000 | 1,499,000 | ||||||
Other Commitment | 2,537,000 | 2,537,000 | ||||||
Operating Lease Obligations | ||||||||
Other Commitments [Line Items] | ||||||||
October - December 2017 | 12,000 | 12,000 | ||||||
2,018 | 43,000 | 43,000 | ||||||
2,019 | 32,000 | 32,000 | ||||||
2,020 | 32,000 | 32,000 | ||||||
2,021 | 32,000 | 32,000 | ||||||
2022 and Thereafter | 189,000 | 189,000 | ||||||
Other Commitment | 340,000 | 340,000 | ||||||
Capital Lease and Other Obligations | ||||||||
Other Commitments [Line Items] | ||||||||
October - December 2017 | 20,000 | 20,000 | ||||||
2,018 | 74,000 | 74,000 | ||||||
2,019 | 45,000 | 45,000 | ||||||
2,020 | 42,000 | 42,000 | ||||||
2,021 | 29,000 | 29,000 | ||||||
2022 and Thereafter | 145,000 | 145,000 | ||||||
Other Commitment | $ 355,000 | 355,000 | ||||||
Consent Decree | ||||||||
Other Commitments [Line Items] | ||||||||
Civil penalty | $ 4,950 | $ 54,700 | ||||||
Mitigation projects | 4,500 | |||||||
Supplemental environmental projects | $ 4,000 | |||||||
Maximum | Marcellus Shale | Transportation Agreement Commitments | ||||||||
Other Commitments [Line Items] | ||||||||
Term | 15 years | |||||||
Scenario, Forecast | Transportation Agreement Commitments | ||||||||
Other Commitments [Line Items] | ||||||||
Other Commitment | $ 627,000 | |||||||
Civil Penalty | ||||||||
Other Commitments [Line Items] | ||||||||
Settlement amount | $ 24,710 | |||||||
Payment to approved SEP | ||||||||
Other Commitments [Line Items] | ||||||||
Settlement amount | $ 98,840 |