Document and Entity Information
Document and Entity Information Document Document - shares | 9 Months Ended | |
Sep. 30, 2017 | Oct. 20, 2017 | |
Entity Information [Line Items] | ||
Entity Registrant Name | PDC ENERGY, INC. | |
Entity Central Index Key | 77,877 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 65,872,790 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 136,429 | $ 244,100 |
Accounts receivable, net | 167,276 | 143,392 |
Fair value of derivatives | 22,916 | 8,791 |
Prepaid expenses and other current assets | 8,081 | 3,542 |
Total current assets | 334,702 | 399,825 |
Properties and equipment, net | 3,882,700 | 4,002,994 |
Assets held-for-sale, net | 41,484 | 5,272 |
Fair value of derivatives | 4,605 | 2,386 |
Goodwill | 0 | 62,041 |
Other assets | 43,796 | 13,324 |
Total Assets | 4,307,287 | 4,485,842 |
Current liabilities: | ||
Accounts payable | 164,080 | 66,322 |
Production tax liability | 36,954 | 24,767 |
Fair value of derivatives | 25,987 | 53,595 |
Funds held for distribution | 94,387 | 71,339 |
Accrued interest payable | 18,929 | 15,930 |
Other accrued expenses | 33,451 | 38,625 |
Total current liabilities | 373,788 | 270,578 |
Long-term debt | 1,051,571 | 1,043,954 |
Deferred income tax | 326,472 | 400,867 |
Asset retirement obligation | 78,188 | 82,612 |
Fair value of derivatives | 7,261 | 27,595 |
Other liabilities | 43,405 | 37,482 |
Total liabilities | 1,880,685 | 1,863,088 |
Commitments and contingent liabilities | ||
Stockholders' Equity: | ||
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,797,748 and 65,704,568 issued as of March 31, 2017 and December 31, 2016, respectively | 659 | 657 |
Additional paid-in capital | 2,500,532 | 2,489,557 |
Retained earnings | (70,933) | 134,208 |
Treasury shares - at cost, 34,433 and 28,763 as of March 31, 2017 and December 31, 2016, respectively | (3,656) | (1,668) |
Total stockholders' equity | 2,426,602 | 2,622,754 |
Total Liabilities and Stockholders' Equity | $ 4,307,287 | $ 4,485,842 |
Balance Sheet Parenthetical (Pa
Balance Sheet Parenthetical (Parentheticals) - $ / shares | Sep. 30, 2017 | Dec. 31, 2016 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Common stock, shares issued | 65,928,295 | 65,704,568 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Treasury shares, at cost | 62,772 | 28,763 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Revenues: | ||||
Crude oil, natural gas and NGLs sales | $ 232,733 | $ 141,805 | $ 636,027 | $ 328,013 |
Commodity price risk management gain, net of settlements | (52,178) | 19,397 | 86,458 | (62,348) |
Other income | 2,680 | 2,688 | 9,615 | 9,153 |
Total revenues | 183,235 | 163,890 | 732,100 | 274,818 |
Costs, expenses and other: | ||||
Lease operating expenses | 25,353 | 14,001 | 65,170 | 43,006 |
Production taxes | 15,516 | 9,568 | 42,957 | 19,682 |
Transportation, gathering and processing expenses | 9,794 | 5,048 | 22,184 | 13,554 |
General and administrative expense | 29,299 | 32,510 | 85,145 | 78,868 |
Exploration, geologic, and geophysical expense | 41,908 | 241 | 43,895 | 688 |
Depreciation, depletion and amortization | 125,238 | 112,927 | 360,567 | 317,329 |
Impairment of properties and equipment | 252,740 | 933 | 282,499 | 6,104 |
Impairment of goodwill | 75,121 | 0 | 75,121 | 0 |
Accretion of asset retirement obligation | 1,472 | 1,777 | 4,906 | 5,400 |
Gain on sale of properties and equipment | (62) | (219) | (754) | (43) |
Provision for uncollectible notes receivable | 0 | (700) | (40,203) | 44,038 |
Other expenses | 2,947 | 3,092 | 10,365 | 7,795 |
Total cost, expenses and other | 579,326 | 179,178 | 951,852 | 536,421 |
Loss from operations | (396,091) | (15,288) | (219,752) | (261,603) |
Interest expense | (19,275) | (20,193) | (58,359) | (42,759) |
Interest income | 479 | 140 | 1,487 | 1,875 |
Loss before income taxes | (414,887) | (35,341) | (276,624) | (302,487) |
Income tax benefit | 122,350 | 12,032 | 71,483 | 112,198 |
Net loss | $ (292,537) | $ (23,309) | $ (205,141) | $ (190,289) |
Earnings per share: | ||||
Basic | $ (4.44) | $ (0.48) | $ (3.12) | $ (4.16) |
Diluted | $ (4.44) | $ (0.48) | $ (3.12) | $ (4.16) |
Weighted-average common shares outstanding | ||||
Basic | 65,865 | 48,839 | 65,825 | 45,741 |
Diluted | 65,865 | 48,839 | 65,825 | 45,741 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Net loss | $ (205,141) | $ (190,289) |
Net loss | (205,141) | (190,289) |
Adjustments to net income (loss) to reconcile to net cash provided by operating activities: | ||
Net change in fair value of unsettled derivatives | (64,307) | 230,177 |
Depreciation, depletion and amortization | 360,567 | 317,329 |
Impairment of properties and equipment | 282,499 | 6,104 |
Impairment of goodwill | 75,121 | 0 |
Exploratory dry hole costs | 41,187 | 0 |
Provision for uncollectible notes receivable | (40,203) | 44,038 |
Accretion of asset retirement obligation | 4,906 | 5,400 |
Non-cash stock-based compensation | 14,587 | 15,205 |
Gain on sale of properties and equipment | (754) | (43) |
Amortization of debt discount and issuance costs | 9,628 | 12,951 |
Deferred income taxes | (71,529) | (114,136) |
Other | 986 | (526) |
Changes in assets and liabilities | 3,855 | 34,621 |
Net cash from operating activities | 411,402 | 360,831 |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | (528,850) | (352,213) |
Capital expenditures for other properties and equipment | (3,740) | (1,509) |
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition | (14,482) | (100,000) |
Proceeds from sale of properties and equipment | 3,322 | 4,945 |
Sale of promissory note | 40,203 | 0 |
Restricted cash | (9,250) | 0 |
Sale of short-term investments | 49,890 | 0 |
Purchases of short-term investments | (49,890) | 0 |
Net cash from investing activities | (512,797) | (448,777) |
Cash flows from financing activities: | ||
Proceeds from issuance of equity, net of issuance costs | 0 | 855,072 |
Proceeds from senior notes | 0 | 392,250 |
Proceeds from Convertible Debt | 0 | 193,979 |
Proceeds from revolving credit facility | 0 | 85,000 |
Repayment of revolving credit facility | 0 | (122,000) |
Redemption of convertible notes | 0 | (115,000) |
Purchase of treasury shares | (5,325) | (5,106) |
Other | (951) | 593 |
Net cash from financing activities | (6,276) | 1,284,788 |
Net change in cash and cash equivalents | (107,671) | 1,196,842 |
Cash and cash equivalents, beginning of period | 244,100 | 850 |
Cash and cash equivalents, end of period | 136,429 | 1,197,692 |
Cash payments (receipts) for: | ||
Interest, net of capitalized interest | 45,719 | 19,499 |
Income taxes | (2,623) | 167 |
Non-cash investing and financing activities: | ||
Change in accounts payable related to purchases of properties and equipment | (89,974) | (31,497) |
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | 3,357 | 1,137 |
Purchase of properties and equipment under capital leases | $ 3,363 | $ 1,231 |
Consolidated Statement of Equit
Consolidated Statement of Equity (Statement) - USD ($) | Total | Parent [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Treasury Stock [Member] |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | ||||||
Shares, Issued | 65,704,568 | (28,763) | ||||
Issuance of stock awards, net of forfeitures | 273,173 | |||||
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract] | ||||||
Purchase of treasury shares | (80,572) | |||||
Issuance of treasury shares | (49,446) | 49,446 | ||||
Non-employee directors' deferred compensation plan | (2,883) | |||||
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016 | $ 2,622,754,000 | $ 657,000 | $ 2,489,557,000 | $ 134,208,000 | $ (1,668,000) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Purchase of treasury shares | $ (5,325,000) | (5,325,000) | (5,325,000) | |||
Issuance of stock awards, net of forfeitures | 0 | 2,000 | (2,000) | |||
Share-based Compensation expense | 14,587,000 | 14,587,000 | 14,587,000 | |||
Issuance of treasury shares | 0 | 0 | (3,513,000) | 3,513,000 | ||
Non-employee directors' deferred compensation plan | (176,000) | 0 | (176,000) | |||
Net income (Loss) attributable to shareholders | (205,141,000) | (205,141,000) | (205,141,000) | |||
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2017 | 2,426,602,000 | $ 659,000 | $ 2,500,532,000 | $ (70,933,000) | $ (3,656,000) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Stockholders' Equity, Other | $ (97,000) | $ (97,000) | ||||
Shares, Issued | 65,928,295 | (62,772) |
NATURE OF OPERATIONS AND BASIS
NATURE OF OPERATIONS AND BASIS OF PRESENTATION | 9 Months Ended |
Sep. 30, 2017 | |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract] | |
Nature of Operations | NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. We also have operations in the Utica Shale in Southeastern Ohio. During the third quarter of 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. As of September 30, 2017 , we owned an interest in approximately 2,900 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our two affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2016 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2016 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year or any other future period. Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity. |
Recent Accounting Standards
Recent Accounting Standards | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Recently Adopted Accounting Standard In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing. Recently Issued Accounting Standards In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we are performing a comprehensive review of our significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. We have not made a complete determination regarding the impact that the adoption will have on our consolidated financial statements as of the time of this filing. In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements. |
Business Combination Business C
Business Combination Business Combinations (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | BUSINESS COMBINATION Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which was accounted for as a business combination. The acquisition consisted of the purchase of stock of an entity and assets of other entities under common control. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion , after preliminary post-closing adjustments. The total consideration to sellers was comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the sellers at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The purchase accounting for the entity of which we acquired the stock reflected oil and gas assets that did not receive fair value step-up of the tax basis. As a result, a significant deferred income tax liability was calculated based on the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This calculation resulted in approximately $375.0 million of non-cash basis needing to be allocated to the acquired assets. No deferred tax liability was established for the calculated goodwill as the goodwill did not qualify as tax goodwill. The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and include customary post-closing adjustments. The most significant item to be completed during the final purchase price allocation in the third quarter of 2017 was the final allocation of value to the unproved oil and gas properties associated with the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of the value of goodwill has been adjusted for all post-closing adjustments. The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands): September 30, 2017 Acquisition costs: Cash, net of cash acquired $ 905,962 Retirement of seller's debt 40,000 Total cash consideration 945,962 Common stock, 9.4 million shares 690,702 Other purchase price adjustments 426 Total acquisition costs $ 1,637,090 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 6,401 Crude oil and natural gas properties - proved 216,000 Crude oil and natural gas properties - unproved 1,697,000 Infrastructure, pipeline, and other 33,153 Construction in progress 12,323 Goodwill 75,121 Total assets acquired 2,039,998 Liabilities assumed: Current liabilities (24,496 ) Asset retirement obligations (3,705 ) Deferred tax liabilities, net (374,707 ) Total liabilities assumed (402,908 ) Total identifiable net assets acquired $ 1,637,090 The fair value measurements of assets acquired and liabilities assumed 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 future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. Within the unproven properties, the allocation of the value to the underlying leases also required significant judgment and was based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change. This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future, such as production from future development of additional producing zones. The amount of the final goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million and was higher than the initial estimated amount recorded as of December 31, 2016, primarily related to finalization of the aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value assigned to goodwill was not expected to be deductible for income tax purposes. The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the quarter ended September 30, 2017 : Amount (in thousands) Preliminary purchase price allocation $ 62,041 Adjustments 13,080 Final purchase price allocation $ 75,121 See the footnote titled Goodwill for the details regarding the impairment of goodwill as of September 30, 2017 . |
Pending Acquisition and Acreage
Pending Acquisition and Acreage Exchanges Pending Acquisition and Acreage Exchanges (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment | |
Property, Plant and Equipment Disclosure | PENDING ACQUISITION AND ACREAGE EXCHANGES Pending Acquisition. In September 2017, we entered into an acquisition agreement to acquire certain assets from Bayswater Exploration & Production, LLC ("Bayswater") and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 operated drilled uncompleted wells ("DUCs"), and an estimated 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets on our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and is expected to be funded by a combination of available cash and debt. Pending Acreage Exchanges. In September 2017, we entered into an acreage exchange transaction to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we expect to receive approximately 11,700 net acres in exchange for approximately 12,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. The acreage exchange is expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied. In June 2017, we entered into an acreage exchange transaction that also involves the consolidation of certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we estimate that we will receive approximately 3,900 net acres in exchange for approximately 4,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close in the fourth quarter 2017; however, there can be no assurance that conditions to closing will be satisfied. PROPERTIES AND EQUIPMENT AND ASSETS HELD-FOR-SALE The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"): September 30, 2017 December 31, 2016 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 3,759,501 $ 3,499,718 Unproved 1,559,717 1,874,671 Total crude oil and natural gas properties 5,319,218 5,374,389 Infrastructure, pipeline, and other 104,568 62,093 Land and buildings 10,714 6,392 Construction in progress 177,341 122,591 Properties and equipment, at cost 5,611,841 5,565,465 Accumulated DD&A (1,729,141 ) (1,562,471 ) Properties and equipment, net $ 3,882,700 $ 4,002,994 The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Impairment of unproved properties $ 252,623 $ 338 $ 282,188 $ 2,391 Amortization of individually insignificant unproved properties 117 595 311 681 Impairment of crude oil and natural gas properties 252,740 933 282,499 3,072 Land and buildings — — — 3,032 Total impairment of properties and equipment $ 252,740 $ 933 $ 282,499 $ 6,104 During the three months ended September 30, 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment of these unproved properties was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assets were not impaired during the period. Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities, that are expected to be assumed by the purchasers: September 30, 2017 December 31, 2016 (in thousands) Assets Properties and equipment, net $ 41,983 $ 5,272 Total assets $ 41,983 $ 5,272 Liabilities Asset retirement obligation $ 499 $ — Total liabilities $ 499 $ — Net assets $ 41,484 $ 5,272 |
Exploration, Geologic, and Geop
Exploration, Geologic, and Geophysical Expense (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | EXPLORATION, GEOLOGIC, AND GEOPHYSICAL EXPENSE The following table presents the major components of exploration, geologic, and geophysical expense: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Exploratory dry hole costs $ 41,187 $ — $ 41,187 $ — Geological and geophysical costs, including seismic purchases 463 — 1,790 — Operating, personnel and other 258 241 918 688 Total exploration, geologic, and geophysical expense $ 41,908 $ 241 $ 43,895 $ 688 Exploratory dry hole costs. During the three and nine months ended September 30, 2017 , two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.2 million . The conclusion to expense these items was due to the conclusion that the acreage on which these wells were drilled was exploratory in nature and, following drilling, the lack of hydrocarbon production necessary for the wells to be deemed economically viable. |
Properties and Equipment
Properties and Equipment | 9 Months Ended |
Sep. 30, 2017 | |
Oil and Gas Property [Abstract] | |
Property, Plant and Equipment Disclosure | PENDING ACQUISITION AND ACREAGE EXCHANGES Pending Acquisition. In September 2017, we entered into an acquisition agreement to acquire certain assets from Bayswater Exploration & Production, LLC ("Bayswater") and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 operated drilled uncompleted wells ("DUCs"), and an estimated 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets on our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and is expected to be funded by a combination of available cash and debt. Pending Acreage Exchanges. In September 2017, we entered into an acreage exchange transaction to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we expect to receive approximately 11,700 net acres in exchange for approximately 12,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. The acreage exchange is expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied. In June 2017, we entered into an acreage exchange transaction that also involves the consolidation of certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we estimate that we will receive approximately 3,900 net acres in exchange for approximately 4,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close in the fourth quarter 2017; however, there can be no assurance that conditions to closing will be satisfied. PROPERTIES AND EQUIPMENT AND ASSETS HELD-FOR-SALE The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"): September 30, 2017 December 31, 2016 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 3,759,501 $ 3,499,718 Unproved 1,559,717 1,874,671 Total crude oil and natural gas properties 5,319,218 5,374,389 Infrastructure, pipeline, and other 104,568 62,093 Land and buildings 10,714 6,392 Construction in progress 177,341 122,591 Properties and equipment, at cost 5,611,841 5,565,465 Accumulated DD&A (1,729,141 ) (1,562,471 ) Properties and equipment, net $ 3,882,700 $ 4,002,994 The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Impairment of unproved properties $ 252,623 $ 338 $ 282,188 $ 2,391 Amortization of individually insignificant unproved properties 117 595 311 681 Impairment of crude oil and natural gas properties 252,740 933 282,499 3,072 Land and buildings — — — 3,032 Total impairment of properties and equipment $ 252,740 $ 933 $ 282,499 $ 6,104 During the three months ended September 30, 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment of these unproved properties was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assets were not impaired during the period. Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities, that are expected to be assumed by the purchasers: September 30, 2017 December 31, 2016 (in thousands) Assets Properties and equipment, net $ 41,983 $ 5,272 Total assets $ 41,983 $ 5,272 Liabilities Asset retirement obligation $ 499 $ — Total liabilities $ 499 $ — Net assets $ 41,484 $ 5,272 |
Goodwill (Notes)
Goodwill (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Goodwill [Line Items] | |
Goodwill Disclosure [Text Block] | GOODWILL The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was determined to be $75.1 million . With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin since the time of the acquisition, in conjunction with our lower future commodity price outlook, we determined a triggering event had occurred in the quarter ended September 30, 2017. In addition to the factors mentioned above, we also considered our recent impairments of certain unproven leasehold costs, and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill asset group, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in the quarter ended September 30, 2017 . |
Derivative Financial Instrument
Derivative Financial Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas, and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of September 30, 2017 , we had derivative instruments, which were comprised of collars, fixed-price swaps, and basis protection swaps, in place for a portion of our anticipated 2017 and 2018 production for a total of 14,337 MBbls of crude oil, 69,715 BBtu of natural gas, and 412 MBbls of propane. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations. The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets: Fair Value Derivative instruments: Condensed consolidated balance sheet line item September 30, 2017 December 31, 2016 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 19,042 $ 8,490 Basis protection derivative contracts Fair value of derivatives 3,874 301 22,916 8,791 Non-current Commodity derivative contracts Fair value of derivatives 3,942 1,123 Basis protection derivative contracts Fair value of derivatives 663 1,263 4,605 2,386 Total derivative assets $ 27,521 $ 11,177 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 25,895 $ 53,565 Basis protection derivative contracts Fair value of derivatives 92 30 25,987 53,595 Non-current Commodity derivative contracts Fair value of derivatives 7,244 27,595 Basis protection derivative contracts Fair value of derivatives 17 — 7,261 27,595 Total derivative liabilities $ 33,248 $ 81,190 The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations: Three Months Ended September 30, Nine Months Ended September 30, Condensed consolidated statement of operations line item 2017 2016 2017 2016 (in thousands) Commodity price risk management gain, net Net settlements $ 9,585 $ 47,728 $ 22,151 $ 167,859 Net change in fair value of unsettled derivatives (61,763 ) (28,331 ) 64,307 (230,207 ) Total commodity price risk management gain, net $ (52,178 ) $ 19,397 $ 86,458 $ (62,348 ) Net settlements of commodity derivatives decreased for the three and nine months ended September 30, 2017 as compared to the three and nine months ended September 30, 2016 . We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements settled by the end of 2016. Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based on forward strip pricing at September 30, 2017 , we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016. All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of September 30, 2017 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 27,521 $ (15,010 ) $ 12,511 Liability derivatives: Derivative instruments, at fair value $ 33,248 $ (15,010 ) $ 18,238 As of December 31, 2016 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,177 $ (10,930 ) $ 247 Liability derivatives: Derivative instruments, at fair value $ 81,190 $ (10,930 ) $ 70,260 |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value, Measurement Inputs, Disclosure | FAIR VALUE OF FINANCIAL INSTRUMENTS Determination of Fair Value Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Derivative Financial Instruments We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement through the review of counterparty statements and other supporting documentation, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information, and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: September 30, 2017 December 31, 2016 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Total assets $ 24,553 $ 2,968 $ 27,521 $ 6,350 $ 4,827 $ 11,177 Total liabilities (23,811 ) (9,437 ) (33,248 ) (66,789 ) (14,401 ) (81,190 ) Net asset (liability) $ 742 $ (6,469 ) $ (5,727 ) $ (60,439 ) $ (9,574 ) $ (70,013 ) The following table presents a reconciliation of our Level 3 assets measured at fair value: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 8,619 $ 27,375 $ (9,574 ) $ 91,288 Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (14,075 ) 4,234 8,547 (16,023 ) Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net (1,013 ) (15,587 ) (5,442 ) (59,243 ) Fair value of Level 3 instruments, net asset end of period $ (6,469 ) $ 16,022 $ (6,469 ) $ 16,022 Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: Commodity price risk management gain ( loss) , net $ (8,711 ) $ (2,240 ) $ (583 ) $ (8,273 ) The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by this report. Non-Derivative Financial Assets and Liabilities The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation. The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of September 30, 2017 . Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 196.3 98.1 % 2022 Senior Notes 521.9 104.4 % 2024 Senior Notes 412.5 103.1 % The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease. Concentration of Risk Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. An insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at September 30, 2017 , taking into account the estimated likelihood of nonperformance. Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at September 30, 2017 . We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also major lenders under our revolving credit facility. |
Note Receivable (Notes)
Note Receivable (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Loans, Notes, Trade and Other Receivables Disclosure [Text Block] | NOTE RECEIVABLE In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million , bearing variable interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer could be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate. We regularly analyzed the Promissory Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method. We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure | INCOME TAXES We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items. The effective income tax rates for the three and nine months ended September 30, 2017 were 29.5 percent and 25.8 percent benefit on loss, respectively, compared to 34.0 percent and 37.1 percent benefit on loss for the three and nine months ended September 30, 2016 . The most significant element related to the decrease in the effective income tax rate was the impact from the $75.1 million impairment of the goodwill in the quarter ended September 30, 2017 . This goodwill did not have an associated deferred tax liability at the time it was created, therefore, no deferred tax benefit was realized upon the impairment of the goodwill. The effective income tax rates for the three and nine months ended September 30, 2017 , are based upon a full year forecasted tax benefit on loss. In addition to the impact from the goodwill impairment, the effective income tax rate for the three months ended September 30, 2017 includes discrete income tax benefits of $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state income tax returns. The effective income tax rate for the nine months ended September 30, 2017 includes discrete income tax benefits of $1.8 million relating to the excess income tax benefit recognized with the vesting of stock awards and $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state tax returns. These discrete tax benefits during the three and nine months ended September 30, 2017 resulted in a 0.2 percent and 0.9 percent increase to our effective income tax rates. We anticipate the potential for increased periodic volatility in future effective income tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective income tax rates for the three and nine months ended September 30, 2016 , were based upon a full year forecasted income tax benefit on loss and were greater than the statutory federal income tax rate, primarily due to state income taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. There were no significant discrete income tax items recorded during the three and nine months ended September 30, 2016 . As of September 30, 2017 , there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue to voluntarily participate in the Internal Revenue Service's Compliance Assurance Program for the 2016 and 2017 tax years, and received final acceptance of our 2015 federal income tax return and partial acceptance of the recently filed 2016 federal income tax return that is now going through the IRS CAP post-filing review process. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt consisted of the following as of: September 30, 2017 December 31, 2016 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (32,153 ) (37,475 ) Unamortized debt issuance costs (3,859 ) (4,584 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 163,988 157,941 7.75% Senior Notes due 2022: Principal amount 500,000 500,000 Unamortized debt issuance costs (5,602 ) (6,443 ) 7.75% Senior Notes due 2022, net of unamortized debt issuance costs 494,398 493,557 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,815 ) (7,544 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,185 392,456 Total senior notes 1,051,571 1,043,954 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,051,571 $ 1,043,954 Senior Notes 2021 Convertible Notes. In September 2016 , we issued $200 million of 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in a public offering. The maturity for the payment of principal is September 15, 2021 . Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15 . The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs. As of September 30, 2017 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8 percent . Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares of our common stock, as well as cash in lieu of fractional shares. 2022 Senior Notes. In October 2012 , we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11.0 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. 2024 Senior Notes. In September 2016 , we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, and the 2024 Senior Notes (collectively, the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc. became a guarantor of our obligations under the Notes. Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor . As of September 30, 2017 , we were in compliance with all covenants related to the Notes, and expect to remain in compliance throughout the next 12-month period. Revolving Credit Facility Revolving Credit Facility. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1.0 billion in allowable borrowing capacity, subject to the borrowing base and certain limitations under our senior notes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. In May 2017, we entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amended the revolving credit facility to reflect an increase in the borrowing base from $700 million to $950 million . In addition, the Fifth Amendment made changes to certain of the financial and non-financial covenants in the existing agreement, as well as other administrative changes. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment amends the revolving credit facility to allow the borrowing base to increase above the maximum allowable borrowing capacity of $1.0 billion . We have elected to increase the fall 2017 borrowing base to $1.1 billion and maintain a $700 million commitment level as of the date of this report. As of September 30, 2017, available funds under our revolving credit facility were $700 million based on our elected commitment level. As of September 30, 2017 and December 31, 2016 , debt issuance costs related to our revolving credit facility were $6.8 million and $8.8 million , respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of September 30, 2017 or December 31, 2016 . The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of September 30, 2017 , the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent . No principal payments are generally required until the revolving credit facility expires in May 2020, or in the event that the borrowing base falls below the outstanding balance. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of September 30, 2017 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.8 and our current ratio was 2.9 as of September 30, 2017 . |
Other Accrued Expenses Other Ac
Other Accrued Expenses Other Accrued Expenses (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Other Accrued Expenses [Abstract] | |
Other Income and Other Expense Disclosure [Text Block] | OTHER ACCRUED EXPENSES Other Accrued Expenses. The following table presents the components of other accrued expenses as of: September 30, 2017 December 31, 2016 (in thousands) Employee benefits $ 14,401 $ 22,282 Asset retirement obligations 13,128 9,775 Other 5,922 6,568 Other accrued expenses $ 33,451 $ 38,625 |
Capital Leases (Notes)
Capital Leases (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Capital Leased Assets [Line Items] | |
Capital Leases in Financial Statements of Lessee Disclosure [Text Block] | CAPITAL LEASES We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. The following table presents vehicles under capital lease as of: September 30, 2017 December 31, 2016 (in thousands) Vehicles $ 6,301 $ 2,975 Accumulated depreciation (1,435 ) (776 ) $ 4,866 $ 2,199 Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending September 30, Amount (in thousands) 2018 $ 2,207 2019 1,617 2020 1,758 5,582 Less executory cost (258 ) Less amount representing interest (615 ) Present value of minimum lease payments $ 4,709 Short-term capital lease obligations $ 1,768 Long-term capital lease obligations 2,941 $ 4,709 Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets and long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Disclosure | ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties: Amount (in thousands) Balance at December 31, 2016 $ 92,387 Obligations incurred with development activities 3,296 Accretion expense 4,906 Revisions in estimated cash flows 155 Obligations discharged with asset retirements (8,929 ) Balance at September 30, 2017 91,815 Less liabilities held for sale (499 ) Less current portion (13,128 ) Long-term portion $ 78,188 Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. As of September 30, 2017 , the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure | COMMITMENTS AND CONTINGENCIES Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. The following table presents gross volume information related to our long-term firm transportation and processing agreements for pipeline capacity: For the Twelve Months Ending September 30, Area 2018 2019 2020 2021 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field — 16,760 30,850 31,025 131,287 209,922 March 31, 2026 Delaware Basin 14,600 14,600 14,640 3,680 — 47,520 December 31, 2020 Gas Marketing 7,117 7,117 7,136 7,117 6,227 34,714 August 31, 2022 Utica Shale 2,738 2,738 2,745 2,738 5,016 15,975 July 22, 2023 Total 24,455 41,215 55,371 44,560 142,530 308,131 Crude oil (MBbls) Wattenberg Field 2,413 2,413 1,812 — — 6,638 June 30, 2020 Dollar commitment (in thousands) $ 18,410 $ 35,170 $ 44,949 $ 33,776 $ 129,546 $ 261,851 In anticipation of our future drilling activities in the Wattenberg Field, we entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month after the actual in-service date of the plants, which in the above table is scheduled to be in the fourth quarter of 2018 for the first plant and April 2019 for the second plant. We are currently working with this midstream provider to identify opportunities to accelerate the completion of the first of these processing facilities. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will support the utilization of the incremental commitments. In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas. For each of the three and nine months ended September 30, 2017 , commitments for long-term transportation volumes, net to our interest, for Wattenberg Field crude oil, Delaware Basin natural gas, and Utica Shale natural gas were $2.6 million and $7.4 million , respectively, and were recorded in transportation, gathering, and processing expenses in our condensed consolidated statements of operations. For each of the three and nine months ended September 30, 2016 , commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.6 million and $7.2 million , respectively. Litigation and Legal Items. The Company is involved in various legal proceedings. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. Management has provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of September 30, 2017 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws will not be discovered on our properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. Clean Air Act Tentative Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. For more than a year, we held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA and the State of Colorado filed a complaint against us based on the above matters. We continued to conduct meetings with these agencies in working toward a resolution of the matters. On September 28, 2017, the parties jointly filed for an extension of time for PDC to reply to the complaint. The extension was requested because the parties reached an agreement to resolve the case subject to final approval by the appropriate persons within the federal government and state government, as well as outcome of the period of public comment on the proposed decree. A consent decree was signed by all parties on October 31, 2017 and is subject to a 30-day comment period in which it will be publicly published in the Federal Register. The consent decree provides that we will implement changes to our design, operation, and maintenance of most of our field-wide storage tank systems to enhance our emission management in the DJ Basin. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. We voluntarily included in the consent decree approximately 40 additional facilities associated with our pending acquisition of additional assets in the basin. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects); (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. Certain expenditures for the injunctive relief are believed to have been incurred in 2016 and 2017, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Although we believe the consent decree will be approved by the court following the comment period, this cannot be guaranteed. |
Common Stock
Common Stock | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | COMMON STOCK Sale of Equity Securities During December 2016, we issued 9.4 million shares of our common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties. Pursuant to the terms of previously disclosed lock-up agreements, the resale of these shares was restricted. The lock-up period ended on June 4, 2017. We have registered the 9.4 million shares of our common stock for resale under the Securities Act of 1933. Stock-Based Compensation Plans The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Stock-based compensation expense $ 4,761 $ 4,079 $ 14,587 $ 15,205 Income tax benefit (1,781 ) (1,552 ) (5,457 ) (5,786 ) Net stock-based compensation expense $ 2,980 $ 2,527 $ 9,130 $ 9,419 Stock Appreciation Rights The stock appreciation right ("SARs") vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The Compensation Committee of our Board of Directors awarded SARs to our executive officers during the nine months ended September 30, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Nine Months Ended September 30, 2017 2016 Expected term of award (in years) 6 6 Risk-free interest rate 2.0 % 1.8 % Expected volatility 53.3 % 54.5 % Weighted-average grant date fair value per share $ 38.58 $ 26.96 The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. The following table presents the changes in our SARs for the nine months ended September 30, 2017 : Number of Weighted-Average Average Remaining Contractual Aggregate Intrinsic (in thousands) Outstanding at December 31, 2016 244,078 $ 41.36 6.9 $ 7,620 Awarded 54,142 74.57 — — Outstanding at September 30, 2017 298,220 47.39 6.7 2,043 Exercisable at September 30, 2017 186,248 39.38 5.6 1,867 Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of September 30, 2017 was $2.3 million . The cost is expected to be recognized over a weighted-average period of 1.9 years. Restricted Stock Awards Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the nine months ended September 30, 2017 : Shares Weighted-Average Non-vested at December 31, 2016 479,642 $ 56.09 Granted 260,019 66.00 Vested (206,242 ) 56.44 Forfeited (7,990 ) 64.32 Non-vested at September 30, 2017 525,429 60.73 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Nine Months Ended September 30, 2017 2016 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 13,266 $ 14,675 Total intrinsic value of time-based awards non-vested 25,762 35,079 Market price per common share as of September 30, 49.03 67.06 Weighted-average grant date fair value per share 66.00 57.12 Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of September 30, 2017 was $22.0 million . This cost is expected to be recognized over a weighted-average period of 1.9 years. Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The Compensation Committee of our Board of Directors awarded a total of 28,069 market-based restricted shares to our executive officers during the nine months ended September 30, 2017 . In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2019, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions: Nine Months Ended September 30, 2017 2016 Expected term of award (in years) 3 3 Risk-free interest rate 1.4 % 1.2 % Expected volatility 51.4 % 52.3 % Weighted-average grant date fair value per share $ 94.02 $ 72.54 The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. The following table presents the change in non-vested market-based awards during the nine months ended September 30, 2017 : Shares Weighted-Average Non-vested at December 31, 2016 48,420 $ 64.97 Granted 28,069 94.02 Non-vested at September 30, 2017 76,489 75.63 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of /Nine Months Ended September 30, 2017 2016 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ — $ 1,174 Total intrinsic value of market-based awards non-vested 3,750 5,670 Market price per common share as of September 30, 49.03 67.06 Weighted-average grant date fair value per share 94.02 72.54 Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of September 30, 2017 was $2.9 million . This cost is expected to be recognized over a weighted-average period of 1.9 years. Treasury Share Purchases In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, as amended in June 2013, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares granted may be either authorized but unissued shares, treasury shares, or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of SARs, paid out in the form of cash. In accordance with our stock-based compensation plans, employees and directors may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to additional paid-in capital. As of December 31, 2016 , we had 10,397 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016, we had 18,366 of shares of treasury stock related to a rabbi trust. During the nine months ended September 30, 2017 , we acquired 80,572 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 49,446 shares were reissued and 41,523 shares are available for reissuance pursuant to the 2010 Plan. Preferred Stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board from time to time. Through September 30, 2017 , no preferred shares have been issued. |
Earnings per share
Earnings per share | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents a reconciliation of the weighted-average diluted shares outstanding: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Weighted-average common shares outstanding - basic 65,865 48,839 65,825 45,741 Weighted-average common shares and equivalents outstanding - diluted 65,865 48,839 65,825 45,741 We reported a net loss for the three and nine months ended September 30, 2017 and 2016. As a result, our basic and diluted weighted-average common shares outstanding were the same for each period because the effect of the common share equivalents was anti-dilutive. The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 588 660 585 705 Convertible notes — — — 345 Other equity-based awards 48 97 82 103 Total anti-dilutive common share equivalents 636 757 667 1,153 In September 2016, we issued the 2021 Convertible Notes, which give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During the three and nine months ended September 30, 2017 , the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation. In November 2010, we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible Notes"), which gave the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured in May 2016. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the periods presented. |
Subsidiary Guarantor Subsidiary
Subsidiary Guarantor Subsidiary Guarantor (Notes) | 9 Months Ended |
Sep. 30, 2017 | |
Subsidiary Guarantor [Abstract] | |
Guarantees [Text Block] | SUBSIDIARY GUARANTOR Our subsidiary PDC Permian, Inc. guarantees our obligations under our publicly-registered Notes. The following presents the condensed consolidating financial information separately for: (i) PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; (ii) PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our Notes; (iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and (iv) Parent and subsidiaries on a consolidated basis ("Consolidated"). The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements. The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Condensed Consolidating Balance Sheets September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets $ 299,239 $ 35,463 $ — $ 334,702 Properties and equipment, net 1,911,759 1,970,941 — 3,882,700 Intercompany receivable 199,871 — (199,871 ) — Investment in subsidiaries 1,467,623 — (1,467,623 ) — Noncurrent assets 89,245 640 — 89,885 Total Assets $ 3,967,737 $ 2,007,044 $ (1,667,494 ) $ 4,307,287 Liabilities and Stockholders' Equity Current liabilities $ 310,997 $ 62,791 $ — $ 373,788 Intercompany payable — 199,871 (199,871 ) — Long-term debt 1,051,571 — — 1,051,571 Other noncurrent liabilities 178,567 276,759 — 455,326 Stockholders' equity 2,426,602 1,467,623 (1,467,623 ) 2,426,602 Total Liabilities and Stockholders' Equity $ 3,967,737 $ 2,007,044 $ (1,667,494 ) $ 4,307,287 Condensed Consolidating Balance Sheets December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets $ 387,309 $ 12,516 $ — $ 399,825 Properties and equipment, net 1,884,147 2,118,847 — 4,002,994 Intercompany receivable 9,415 — (9,415 ) — Investment in subsidiaries 1,765,092 — (1,765,092 ) — Goodwill — 62,041 — 62,041 Noncurrent assets 20,811 171 — 20,982 Total Assets $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Liabilities and Stockholders' Equity Current liabilities $ 235,121 $ 35,457 $ — $ 270,578 Intercompany payable — 9,415 (9,415 ) — Long-term debt 1,043,954 — — 1,043,954 Other noncurrent liabilities 164,945 383,611 — 548,556 Stockholders' equity 2,622,754 1,765,092 (1,765,092 ) 2,622,754 Total Liabilities and Stockholders' Equity $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Condensed Consolidating Statements of Operations Three Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Operating and other revenues $ 150,015 $ 33,220 $ — $ 183,235 Production and other operating expenses 41,891 13,129 — 55,020 General and administrative 26,207 3,092 — 29,299 Exploration, geologic, and geophysical expense 217 41,691 — 41,908 Depreciation depletion and amortization 106,623 18,615 — 125,238 Impairment of properties and equipment 1,148 251,592 — 252,740 Impairment of goodwill — 75,121 — 75,121 Interest (expense) income (19,168 ) 372 — (18,796 ) Loss before income taxes (45,239 ) (369,648 ) — (414,887 ) Income tax benefit 30,274 92,076 — 122,350 Equity in loss of subsidiary (277,572 ) — 277,572 — Net loss $ (292,537 ) $ (277,572 ) $ 277,572 $ (292,537 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Operating and other revenues $ 657,102 $ 74,998 $ — $ 732,100 Production and other operating expenses 118,779 26,049 — 144,828 General and administrative 76,353 8,792 — 85,145 Exploration, geologic, and geophysical expense 744 43,151 — 43,895 Depreciation depletion and amortization 317,088 43,479 — 360,567 Impairment of properties and equipment 2,282 280,217 — 282,499 Impairment of goodwill — 75,121 — 75,121 Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Interest (expense) income (57,557 ) 685 — (56,872 ) Income (loss) before income taxes 124,502 (401,126 ) — (276,624 ) Income tax expense (benefit) (32,174 ) 103,657 — 71,483 Equity in loss of subsidiary (297,469 ) — 297,469 — Net loss $ (205,141 ) $ (297,469 ) $ 297,469 $ (205,141 ) Net losses of the Guarantor for the three and nine months ended September 30, 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions during the relevant periods, and the impairment of goodwill during the three months ended September 30, 2017 . Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 382,715 $ 28,687 $ — $ 411,402 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (315,718 ) (213,132 ) — (528,850 ) Capital expenditures for other properties and equipment (2,488 ) (1,252 ) — (3,740 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (19,761 ) 5,279 — (14,482 ) Proceeds from sale of properties and equipment 3,322 — — 3,322 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sales of short-term investments 49,890 — — 49,890 Purchases of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (189,239 ) — 189,239 — Net cash from investing activities (492,931 ) (209,105 ) 189,239 (512,797 ) Cash flows from financing activities: Purchase of treasury stock (5,325 ) — — (5,325 ) Other (906 ) (45 ) — (951 ) Intercompany transfers — 189,239 (189,239 ) — Net cash from financing activities (6,231 ) 189,194 (189,239 ) (6,276 ) Net change in cash and cash equivalents (116,447 ) 8,776 — (107,671 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 124,040 $ 12,389 $ — $ 136,429 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Consolidation, Policy | The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our two affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation |
Basis of Accounting, Policy | In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2016 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2016 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year or any other future period |
Reclassification, Policy | . Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity. |
Recently Issued Accounting Policy [Policy Text Block] | Recently Issued Accounting Standards In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we are performing a comprehensive review of our significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. We have not made a complete determination regarding the impact that the adoption will have on our consolidated financial statements as of the time of this filing. In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements. |
Earnings Per Share, Policy | Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. |
Business Combination Business27
Business Combination Business Combinations (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Business Combination, Segment Allocation [Table Text Block] | The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands): September 30, 2017 Acquisition costs: Cash, net of cash acquired $ 905,962 Retirement of seller's debt 40,000 Total cash consideration 945,962 Common stock, 9.4 million shares 690,702 Other purchase price adjustments 426 Total acquisition costs $ 1,637,090 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 6,401 Crude oil and natural gas properties - proved 216,000 Crude oil and natural gas properties - unproved 1,697,000 Infrastructure, pipeline, and other 33,153 Construction in progress 12,323 Goodwill 75,121 Total assets acquired 2,039,998 Liabilities assumed: Current liabilities (24,496 ) Asset retirement obligations (3,705 ) Deferred tax liabilities, net (374,707 ) Total liabilities assumed (402,908 ) Total identifiable net assets acquired $ 1,637,090 |
Business Combination Goodwill (
Business Combination Goodwill (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Goodwill [Abstract] | |
Schedule of Intangible Assets and Goodwill [Table Text Block] | The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the quarter ended September 30, 2017 : Amount (in thousands) Preliminary purchase price allocation $ 62,041 Adjustments 13,080 Final purchase price allocation $ 75,121 |
Exploration, Geologic, and Ge29
Exploration, Geologic, and Geophysical Expense (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | The following table presents the major components of exploration, geologic, and geophysical expense: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Exploratory dry hole costs $ 41,187 $ — $ 41,187 $ — Geological and geophysical costs, including seismic purchases 463 — 1,790 — Operating, personnel and other 258 241 918 688 Total exploration, geologic, and geophysical expense $ 41,908 $ 241 $ 43,895 $ 688 |
Properties and Equipment (Table
Properties and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Long Lived Assets Held-for-sale [Line Items] | |
Disclosure of Long Lived Assets Held-for-sale [Table Text Block] | The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities, that are expected to be assumed by the purchasers: September 30, 2017 December 31, 2016 (in thousands) Assets Properties and equipment, net $ 41,983 $ 5,272 Total assets $ 41,983 $ 5,272 Liabilities Asset retirement obligation $ 499 $ — Total liabilities $ 499 $ — Net assets $ 41,484 $ 5,272 |
Property, Plant and Equipment | The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"): September 30, 2017 December 31, 2016 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 3,759,501 $ 3,499,718 Unproved 1,559,717 1,874,671 Total crude oil and natural gas properties 5,319,218 5,374,389 Infrastructure, pipeline, and other 104,568 62,093 Land and buildings 10,714 6,392 Construction in progress 177,341 122,591 Properties and equipment, at cost 5,611,841 5,565,465 Accumulated DD&A (1,729,141 ) (1,562,471 ) Properties and equipment, net $ 3,882,700 $ 4,002,994 |
Impairment of natural gas and crude oil properties | The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Impairment of unproved properties $ 252,623 $ 338 $ 282,188 $ 2,391 Amortization of individually insignificant unproved properties 117 595 311 681 Impairment of crude oil and natural gas properties 252,740 933 282,499 3,072 Land and buildings — — — 3,032 Total impairment of properties and equipment $ 252,740 $ 933 $ 282,499 $ 6,104 |
Derivative Financial Instrume31
Derivative Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets: Fair Value Derivative instruments: Condensed consolidated balance sheet line item September 30, 2017 December 31, 2016 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 19,042 $ 8,490 Basis protection derivative contracts Fair value of derivatives 3,874 301 22,916 8,791 Non-current Commodity derivative contracts Fair value of derivatives 3,942 1,123 Basis protection derivative contracts Fair value of derivatives 663 1,263 4,605 2,386 Total derivative assets $ 27,521 $ 11,177 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 25,895 $ 53,565 Basis protection derivative contracts Fair value of derivatives 92 30 25,987 53,595 Non-current Commodity derivative contracts Fair value of derivatives 7,244 27,595 Basis protection derivative contracts Fair value of derivatives 17 — 7,261 27,595 Total derivative liabilities $ 33,248 $ 81,190 The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations: Three Months Ended September 30, Nine Months Ended September 30, Condensed consolidated statement of operations line item 2017 2016 2017 2016 (in thousands) Commodity price risk management gain, net Net settlements $ 9,585 $ 47,728 $ 22,151 $ 167,859 Net change in fair value of unsettled derivatives (61,763 ) (28,331 ) 64,307 (230,207 ) Total commodity price risk management gain, net $ (52,178 ) $ 19,397 $ 86,458 $ (62,348 ) Net settlements of commodity derivatives decreased for the three and nine months ended September 30, 2017 as compared to the three and nine months ended September 30, 2016 . We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements settled by the end of 2016. Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based on forward strip pricing at September 30, 2017 , we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016. All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of September 30, 2017 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 27,521 $ (15,010 ) $ 12,511 Liability derivatives: Derivative instruments, at fair value $ 33,248 $ (15,010 ) $ 18,238 As of December 31, 2016 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,177 $ (10,930 ) $ 247 Liability derivatives: Derivative instruments, at fair value $ 81,190 $ (10,930 ) $ 70,260 |
Fair Value Measurements and D32
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 | Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: September 30, 2017 December 31, 2016 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Total assets $ 24,553 $ 2,968 $ 27,521 $ 6,350 $ 4,827 $ 11,177 Total liabilities (23,811 ) (9,437 ) (33,248 ) (66,789 ) (14,401 ) (81,190 ) Net asset (liability) $ 742 $ (6,469 ) $ (5,727 ) $ (60,439 ) $ (9,574 ) $ (70,013 ) |
Fair Value Assets and Liabilities Unobservable Input Reconciliation | The following table presents a reconciliation of our Level 3 assets measured at fair value: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 8,619 $ 27,375 $ (9,574 ) $ 91,288 Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (14,075 ) 4,234 8,547 (16,023 ) Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net (1,013 ) (15,587 ) (5,442 ) (59,243 ) Fair value of Level 3 instruments, net asset end of period $ (6,469 ) $ 16,022 $ (6,469 ) $ 16,022 Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: Commodity price risk management gain ( loss) , net $ (8,711 ) $ (2,240 ) $ (583 ) $ (8,273 ) |
Fair Value Measurements and D33
Fair Value Measurements and Disclosures Fair value of the portion of long-term debt related to senior and convertible notes (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of September 30, 2017 . Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 196.3 98.1 % 2022 Senior Notes 521.9 104.4 % 2024 Senior Notes 412.5 103.1 % |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt consisted of the following as of: September 30, 2017 December 31, 2016 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (32,153 ) (37,475 ) Unamortized debt issuance costs (3,859 ) (4,584 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 163,988 157,941 7.75% Senior Notes due 2022: Principal amount 500,000 500,000 Unamortized debt issuance costs (5,602 ) (6,443 ) 7.75% Senior Notes due 2022, net of unamortized debt issuance costs 494,398 493,557 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,815 ) (7,544 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,185 392,456 Total senior notes 1,051,571 1,043,954 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,051,571 $ 1,043,954 |
Other Accrued Expenses Other 35
Other Accrued Expenses Other Accrued Expenses (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Other Accrued Expenses [Abstract] | |
Schedule of Other Operating Cost and Expense, by Component [Table Text Block] | The following table presents the components of other accrued expenses as of: September 30, 2017 December 31, 2016 (in thousands) Employee benefits $ 14,401 $ 22,282 Asset retirement obligations 13,128 9,775 Other 5,922 6,568 Other accrued expenses $ 33,451 $ 38,625 |
Capital Leases (Tables)
Capital Leases (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Capital Leases [Abstract] | |
Schedule of Capital Leased Assets [Table Text Block] | The following table presents vehicles under capital lease as of: September 30, 2017 December 31, 2016 (in thousands) Vehicles $ 6,301 $ 2,975 Accumulated depreciation (1,435 ) (776 ) $ 4,866 $ 2,199 |
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block] | Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending September 30, Amount (in thousands) 2018 $ 2,207 2019 1,617 2020 1,758 5,582 Less executory cost (258 ) Less amount representing interest (615 ) Present value of minimum lease payments $ 4,709 Short-term capital lease obligations $ 1,768 Long-term capital lease obligations 2,941 $ 4,709 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties: Amount (in thousands) Balance at December 31, 2016 $ 92,387 Obligations incurred with development activities 3,296 Accretion expense 4,906 Revisions in estimated cash flows 155 Obligations discharged with asset retirements (8,929 ) Balance at September 30, 2017 91,815 Less liabilities held for sale (499 ) Less current portion (13,128 ) Long-term portion $ 78,188 |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contigencies (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Supply Commitment | : For the Twelve Months Ending September 30, Area 2018 2019 2020 2021 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field — 16,760 30,850 31,025 131,287 209,922 March 31, 2026 Delaware Basin 14,600 14,600 14,640 3,680 — 47,520 December 31, 2020 Gas Marketing 7,117 7,117 7,136 7,117 6,227 34,714 August 31, 2022 Utica Shale 2,738 2,738 2,745 2,738 5,016 15,975 July 22, 2023 Total 24,455 41,215 55,371 44,560 142,530 308,131 Crude oil (MBbls) Wattenberg Field 2,413 2,413 1,812 — — 6,638 June 30, 2020 Dollar commitment (in thousands) $ 18,410 $ 35,170 $ 44,949 $ 33,776 $ 129,546 $ 261,851 |
Common Stock (Tables)
Common Stock (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Stock-based compensation expense $ 4,761 $ 4,079 $ 14,587 $ 15,205 Income tax benefit (1,781 ) (1,552 ) (5,457 ) (5,786 ) Net stock-based compensation expense $ 2,980 $ 2,527 $ 9,130 $ 9,419 |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions | he Compensation Committee of our Board of Directors awarded SARs to our executive officers during the nine months ended September 30, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Nine Months Ended September 30, 2017 2016 Expected term of award (in years) 6 6 Risk-free interest rate 2.0 % 1.8 % Expected volatility 53.3 % 54.5 % Weighted-average grant date fair value per share $ 38.58 $ 26.96 |
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity | The following table presents the changes in our SARs for the nine months ended September 30, 2017 : Number of Weighted-Average Average Remaining Contractual Aggregate Intrinsic (in thousands) Outstanding at December 31, 2016 244,078 $ 41.36 6.9 $ 7,620 Awarded 54,142 74.57 — — Outstanding at September 30, 2017 298,220 47.39 6.7 2,043 Exercisable at September 30, 2017 186,248 39.38 5.6 1,867 |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the nine months ended September 30, 2017 : Shares Weighted-Average Non-vested at December 31, 2016 479,642 $ 56.09 Granted 260,019 66.00 Vested (206,242 ) 56.44 Forfeited (7,990 ) 64.32 Non-vested at September 30, 2017 525,429 60.73 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Nine Months Ended September 30, 2017 2016 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 13,266 $ 14,675 Total intrinsic value of time-based awards non-vested 25,762 35,079 Market price per common share as of September 30, 49.03 67.06 Weighted-average grant date fair value per share 66.00 57.12 |
Restricted Stock Awards, Market-Based, Valuation assumptions | he Compensation Committee of our Board of Directors awarded a total of 28,069 market-based restricted shares to our executive officers during the nine months ended September 30, 2017 . In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2019, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions: Nine Months Ended September 30, 2017 2016 Expected term of award (in years) 3 3 Risk-free interest rate 1.4 % 1.2 % Expected volatility 51.4 % 52.3 % Weighted-average grant date fair value per share $ 94.02 $ 72.54 |
Schedule of Nonvested Performance-based Units Activity | The following table presents the change in non-vested market-based awards during the nine months ended September 30, 2017 : Shares Weighted-Average Non-vested at December 31, 2016 48,420 $ 64.97 Granted 28,069 94.02 Non-vested at September 30, 2017 76,489 75.63 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of /Nine Months Ended September 30, 2017 2016 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ — $ 1,174 Total intrinsic value of market-based awards non-vested 3,750 5,670 Market price per common share as of September 30, 49.03 67.06 Weighted-average grant date fair value per share 94.02 72.54 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation | The following table presents a reconciliation of the weighted-average diluted shares outstanding: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Weighted-average common shares outstanding - basic 65,865 48,839 65,825 45,741 Weighted-average common shares and equivalents outstanding - diluted 65,865 48,839 65,825 45,741 |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 588 660 585 705 Convertible notes — — — 345 Other equity-based awards 48 97 82 103 Total anti-dilutive common share equivalents 636 757 667 1,153 |
Subsidiary Guarantor Subsidia41
Subsidiary Guarantor Subsidiary Guarantor (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Subsidiary Guarantor [Abstract] | |
Schedule of Guarantor Obligations [Table Text Block] | The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Condensed Consolidating Balance Sheets September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets $ 299,239 $ 35,463 $ — $ 334,702 Properties and equipment, net 1,911,759 1,970,941 — 3,882,700 Intercompany receivable 199,871 — (199,871 ) — Investment in subsidiaries 1,467,623 — (1,467,623 ) — Noncurrent assets 89,245 640 — 89,885 Total Assets $ 3,967,737 $ 2,007,044 $ (1,667,494 ) $ 4,307,287 Liabilities and Stockholders' Equity Current liabilities $ 310,997 $ 62,791 $ — $ 373,788 Intercompany payable — 199,871 (199,871 ) — Long-term debt 1,051,571 — — 1,051,571 Other noncurrent liabilities 178,567 276,759 — 455,326 Stockholders' equity 2,426,602 1,467,623 (1,467,623 ) 2,426,602 Total Liabilities and Stockholders' Equity $ 3,967,737 $ 2,007,044 $ (1,667,494 ) $ 4,307,287 Condensed Consolidating Balance Sheets December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets $ 387,309 $ 12,516 $ — $ 399,825 Properties and equipment, net 1,884,147 2,118,847 — 4,002,994 Intercompany receivable 9,415 — (9,415 ) — Investment in subsidiaries 1,765,092 — (1,765,092 ) — Goodwill — 62,041 — 62,041 Noncurrent assets 20,811 171 — 20,982 Total Assets $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Liabilities and Stockholders' Equity Current liabilities $ 235,121 $ 35,457 $ — $ 270,578 Intercompany payable — 9,415 (9,415 ) — Long-term debt 1,043,954 — — 1,043,954 Other noncurrent liabilities 164,945 383,611 — 548,556 Stockholders' equity 2,622,754 1,765,092 (1,765,092 ) 2,622,754 Total Liabilities and Stockholders' Equity $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Condensed Consolidating Statements of Operations Three Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Operating and other revenues $ 150,015 $ 33,220 $ — $ 183,235 Production and other operating expenses 41,891 13,129 — 55,020 General and administrative 26,207 3,092 — 29,299 Exploration, geologic, and geophysical expense 217 41,691 — 41,908 Depreciation depletion and amortization 106,623 18,615 — 125,238 Impairment of properties and equipment 1,148 251,592 — 252,740 Impairment of goodwill — 75,121 — 75,121 Interest (expense) income (19,168 ) 372 — (18,796 ) Loss before income taxes (45,239 ) (369,648 ) — (414,887 ) Income tax benefit 30,274 92,076 — 122,350 Equity in loss of subsidiary (277,572 ) — 277,572 — Net loss $ (292,537 ) $ (277,572 ) $ 277,572 $ (292,537 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Operating and other revenues $ 657,102 $ 74,998 $ — $ 732,100 Production and other operating expenses 118,779 26,049 — 144,828 General and administrative 76,353 8,792 — 85,145 Exploration, geologic, and geophysical expense 744 43,151 — 43,895 Depreciation depletion and amortization 317,088 43,479 — 360,567 Impairment of properties and equipment 2,282 280,217 — 282,499 Impairment of goodwill — 75,121 — 75,121 Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Interest (expense) income (57,557 ) 685 — (56,872 ) Income (loss) before income taxes 124,502 (401,126 ) — (276,624 ) Income tax expense (benefit) (32,174 ) 103,657 — 71,483 Equity in loss of subsidiary (297,469 ) — 297,469 — Net loss $ (205,141 ) $ (297,469 ) $ 297,469 $ (205,141 ) Net losses of the Guarantor for the three and nine months ended September 30, 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions during the relevant periods, and the impairment of goodwill during the three months ended September 30, 2017 . Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 382,715 $ 28,687 $ — $ 411,402 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (315,718 ) (213,132 ) — (528,850 ) Capital expenditures for other properties and equipment (2,488 ) (1,252 ) — (3,740 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (19,761 ) 5,279 — (14,482 ) Proceeds from sale of properties and equipment 3,322 — — 3,322 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sales of short-term investments 49,890 — — 49,890 Purchases of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (189,239 ) — 189,239 — Net cash from investing activities (492,931 ) (209,105 ) 189,239 (512,797 ) Cash flows from financing activities: Purchase of treasury stock (5,325 ) — — (5,325 ) Other (906 ) (45 ) — (951 ) Intercompany transfers — 189,239 (189,239 ) — Net cash from financing activities (6,231 ) 189,194 (189,239 ) (6,276 ) Net change in cash and cash equivalents (116,447 ) 8,776 — (107,671 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 124,040 $ 12,389 $ — $ 136,429 |
Nature of Operations and Basi42
Nature of Operations and Basis of Presentation Additional Information (Details) | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Oil and gas producing wells, gross | 2,900 |
Number of Operating Segments | 2 |
Business Combination Business43
Business Combination Business Combination (Details) shares in Millions | 3 Months Ended | 9 Months Ended |
Dec. 31, 2016USD ($)aWellsshares | Sep. 30, 2017USD ($) | |
Business Acquisition [Line Items] | ||
Oil and gas producing wells, gross | 2,900 | |
Goodwill | $ 62,041,000 | $ 0 |
Delaware Basin Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Stock Issued During Period, Shares, Acquisitions | shares | 9.4 | |
Gas and Oil Area, Developed, Gross | a | 57,900 | |
Oil and gas producing wells, gross | Wells | 30 | |
Payments to Acquire Business Two, Net of Cash Acquired | 905,962,000 | |
Payments for Deposits Applied to Debt Retirements | 40,000,000 | |
Payments to Acquire Businesses, Gross | $ 945,962,000 | 945,962,000 |
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | 690,702,000 | |
Goodwill, Purchase Accounting Adjustments | 426,000 | |
Business Combination, Consideration Transferred | 1,637,090,000 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | 6,401,000 | |
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties | 216,000,000 | |
business acquisition purchase price allocation unproved properties | 1,697,000,000 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Equipment | 33,153,000 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 12,323,000 | |
Goodwill | $ 62,041,000 | 75,121,000 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 2,039,998,000 | |
Business Combination, Contingent Consideration, Liability, Current | (24,496,000) | |
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | (3,705,000) | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities | (374,707,000) | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities | (402,908,000) | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 1,637,090,000 |
Business Combination Goodwill44
Business Combination Goodwill (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Dec. 31, 2016 | |
Goodwill [Line Items] | ||
Goodwill | $ 0 | $ 62,041 |
Delaware Basin Acquisition [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 75,121 | $ 62,041 |
Goodwill, Purchase Accounting Adjustments | $ 13,080 |
Pending Acquisition and Acrea45
Pending Acquisition and Acreage Exchanges Pending Acquisition and Acreage Exchange (Details) | 9 Months Ended |
Sep. 30, 2017USD ($)aWells | |
Bayswater Acquisition [Member] | |
Property, Plant and Equipment | |
Gas and Oil Area, Developed, Net | 8,300 |
Drilled Uncompleted Wells | 30 |
Gas and Oil Area, Developed, Gross | Wells | 240 |
Other Payments to Acquire Businesses | $ | $ 210,000,000 |
Q4 2017 Drilled Uncompleted Wells | 18 |
Other Payments to Acquire Businesses | $ | $ 21,000,000 |
Third Party 2 acreage to PDC [Member] | |
Property, Plant and Equipment | |
Gas and Oil Area, Developed, Net | 11,700 |
PDC acreage to Third Party 2 [Member] | |
Property, Plant and Equipment | |
Gas and Oil Area, Developed, Net | 12,100 |
Third Party 1 acreage to PDC | |
Property, Plant and Equipment | |
Gas and Oil Area, Developed, Net | 3,900 |
PDC acreage to Third Party 1 | |
Property, Plant and Equipment | |
Gas and Oil Area, Developed, Net | 4,100 |
Exploration, Geologic, and Ge46
Exploration, Geologic, and Geophysical Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||
Dry Hole Costs | $ 41,187 | $ 0 | $ 41,187 | $ 0 |
Geological and geophysical | 463 | 0 | 1,790 | 0 |
Exploratory operating costs | 258 | 241 | 918 | 688 |
Costs Incurred, Exploration Costs | $ 41,908 | $ 241 | $ 43,895 | $ 688 |
Properties and Equipment (Detai
Properties and Equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment | ||
Proved Natural Gas and Crude Oil Properties | $ 3,759,501 | $ 3,499,718 |
Unproved Natural Gas and Crude Oil Properties | 1,559,717 | 1,874,671 |
Total Natural Gas and Crude Oil Properties | 5,319,218 | 5,374,389 |
Equipment and other | 104,568 | 62,093 |
Land and Buildings | 10,714 | 6,392 |
Construction in Progress | 177,341 | 122,591 |
Properties and equipment, at cost | 5,611,841 | 5,565,465 |
Accumulated DD&A | (1,729,141) | (1,562,471) |
Property, Plant and Equipment, Net | $ 3,882,700 | $ 4,002,994 |
Impairment of Natural Gas and C
Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Impairment of natural gas and crude oil properties [Line Items] | ||||
Delaware Basin Unproved Property Impairment | $ 251,600,000 | |||
Impairment of proved ad unproved properties | 252,623,000 | $ 338,000 | $ 282,188,000 | $ 2,391,000 |
Amortization of Individually Insignificant Unproved Properties | 117,000 | 595,000 | 311,000 | 681,000 |
Impairment of Oil and Gas Properties | 252,740,000 | 933,000 | 282,499,000 | 3,072,000 |
Land and buildings | 0 | 0 | 0 | 3,032,000 |
Impairment of properties and equipment | 252,740,000 | $ 933,000 | $ 282,499,000 | $ 6,104,000 |
Impairment of other properties | $ 13,400 |
Properties and Equipment Assets
Properties and Equipment Assets Held for Sale (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Long Lived Assets Held-for-sale [Line Items] | ||
Properties and equipment, net | $ 3,882,700 | $ 4,002,994 |
Assets | 4,307,287 | 4,485,842 |
Asset retirement obligation | 78,188 | 82,612 |
Liabilities | 1,880,685 | 1,863,088 |
Utica Shale | ||
Long Lived Assets Held-for-sale [Line Items] | ||
Properties and equipment, net | 41,983 | 5,272 |
Assets | 41,983 | 5,272 |
Asset retirement obligation | 499 | 0 |
Liabilities | 499 | 0 |
Assets Held-for-sale, Not Part of Disposal Group, Other | $ 41,484 | $ 5,272 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Goodwill [Line Items] | |||||
Goodwill | $ 0 | $ 0 | $ 62,041 | ||
Impairment of goodwill | 75,121 | $ 0 | 75,121 | $ 0 | |
Delaware Basin Acquisition [Member] | |||||
Goodwill [Line Items] | |||||
Goodwill | $ 75,121 | $ 75,121 | $ 62,041 |
Derivative Financial Instrume51
Derivative Financial Instruments Additional Information (Details) | Sep. 30, 2017MBbls |
Crude Oil [Member] | |
Derivatives in Place for Anticipated Production | |
Anticipated crude oil production hedged (MBbls) | 14,337 |
Natural Gas [Member] | |
Derivatives in Place for Anticipated Production | |
Anticipated crude oil production hedged (MBbls) | 69,715.1 |
Natural Gas Liquids [Member] | |
Derivatives in Place for Anticipated Production | |
Anticipated crude oil production hedged (MBbls) | 412 |
Fair Value of Derivative and Ba
Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Derivatives, Fair Value | ||
Derivative Asset, Fair Value, Gross Asset | $ 27,521 | $ 11,177 |
Derivative Liability, Fair Value, Gross Liability | 33,248 | 81,190 |
Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 3,874 | 301 |
Derivative Asset, Fair Value, Gross Asset | 22,916 | 8,791 |
Non Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 663 | 1,263 |
Derivative Asset, Fair Value, Gross Asset | 4,605 | 2,386 |
Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 92 | 30 |
Derivative Liability, Fair Value, Gross Liability | 25,987 | 53,595 |
Non Current Liabilities | ||
Derivatives, Fair Value | ||
Derivative Liability, Fair Value, Gross Liability | 7,261 | 27,595 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 19,042 | 8,490 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Non Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 3,942 | 1,123 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 25,895 | 53,565 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Non Current Liabilities | ||
Derivatives, Fair Value | ||
Derivative Liability, Fair Value, Gross Liability | $ 7,244 | $ 27,595 |
Impact of Derivative Instrument
Impact of Derivative Instruments on Statement of Operations (Details) - Commodity Price Risk Management (loss), net - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Derivative [Line Items] | ||||
Net settlements | $ 9,585 | $ 47,728 | $ 22,151 | $ 167,859 |
Net change in fair value of unsettled derivatives | (61,763) | (28,331) | 64,307 | (230,207) |
Total commodity price risk management gain (loss), net | $ (52,178) | $ 19,397 | $ 86,458 | $ (62,348) |
Derivative Financial Instrume54
Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Derivative Asset: | ||
Derivative assets, gross | $ 27,521 | $ 11,177 |
Effect of master netting agreements | (15,010) | (10,930) |
Derivative asset, net | 12,511 | 247 |
Derivative Liability: | ||
Derivative liability, gross | 33,248 | 81,190 |
Effect of master netting agreements | (15,010) | (10,930) |
Derivative liability, net | $ 18,238 | $ 70,260 |
Fair Value Measurements and D55
Fair Value Measurements and Disclosures (Details) - Fair Value - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Assets and Liabilities at Fair Value | ||
Total assets | $ 27,521 | $ 11,177 |
Total liabilities | (33,248) | (81,190) |
Net asset (fair value) | (5,727) | (70,013) |
Significant Other Observable Inputs (Level 2) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 24,553 | 6,350 |
Total liabilities | (23,811) | (66,789) |
Net asset (fair value) | 742 | (60,439) |
Significant Unobservable Inputs (Level 3) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 2,968 | 4,827 |
Total liabilities | (9,437) | (14,401) |
Net asset (fair value) | $ (6,469) | $ (9,574) |
Reconciliation of Level 3 Fair
Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Roll-forward of Level 3 Assets | ||||
Fair Value, net assets, beginning of period | $ 8,619 | $ 27,375 | $ (9,574) | $ 91,288 |
Fair Value, net assets, end of period | (6,469) | 16,022 | (6,469) | 16,022 |
Commodity Price Risk Management (loss), net | ||||
Roll-forward of Level 3 Assets | ||||
Changes in fair value included in statement of operations line item: | (14,075) | 4,234 | 8,547 | (16,023) |
Settlements included in statement of operations line items: | (1,013) | (15,587) | (5,442) | (59,243) |
Net change in fair value of unsettled derivatives included in statement of operations line item | $ (8,711) | $ (2,240) | $ (583) | $ (8,273) |
Fair Value Measurements and D57
Fair Value Measurements and Disclosures Notes Receivable (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2017 | Sep. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Oct. 14, 2014 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Provision for uncollectible notes receivable | $ 0 | $ (700) | $ (40,203) | $ 44,038 | ||
Notes Receivable | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Provision for uncollectible notes receivable | $ 44,000 | |||||
Note Receivable - Principal Outstanding | $ 39,000 | |||||
1.125% Convertible Senior Notes due 2021 [Member] | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes Payable, Fair Value Disclosure | $ 196,300 | $ 196,300 | ||||
12% Senior Notes fair value | 98.10% | 98.10% | ||||
7.75% Senior Notes due 2022 [Member] | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes Payable, Fair Value Disclosure | $ 521,900 | $ 521,900 | ||||
12% Senior Notes fair value | 104.40% | 104.40% | ||||
6.125% Senior Notes due 2024 [Member] | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes Payable, Fair Value Disclosure | $ 412,500 | $ 412,500 | ||||
12% Senior Notes fair value | 103.10% | 103.10% |
Note Receivable (Details)
Note Receivable (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2017 | Sep. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Oct. 14, 2014 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Provision for uncollectible notes receivable | $ 0 | $ (700) | $ (40,203) | $ 44,038 | ||
Notes Receivable | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes, Loans and Financing Receivable, Gross, Noncurrent | $ 39,000 | |||||
Provision for uncollectible notes receivable | $ 44,000 |
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 | |
Income Tax Disclosure [Abstract] | ||||
Effective Income Tax Rate, Continuing Operations | 29.50% | 34.00% | 25.80% | 37.10% |
Other Tax Expense (Benefit) | $ 1.8 | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 0.20% | 0.90% |
Schedule of Long-Term Debt (Det
Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 | Sep. 14, 2016 |
Debt Instrument | |||
Total senior notes | $ 1,051,571 | $ 1,043,954 | |
Total debt, net of discount and unamortized debt issuance costs | 1,051,571 | 1,043,954 | |
Long-term debt | 1,051,571 | 1,043,954 | |
1.125% Convertible Senior Notes due 2021 [Member] | |||
Debt Instrument | |||
Principal amount | 200,000 | 200,000 | |
Unamortized Discount | (32,153) | (37,475) | |
Unamortized Debt Issuance Expense | (3,859) | (4,584) | $ (4,800) |
3.25% Convertible senior notes due 2016, net of discount | 163,988 | 157,941 | |
7.75% Senior Notes due 2022 [Member] | |||
Debt Instrument | |||
Unamortized Debt Issuance Expense | (5,602) | (6,443) | |
Principal amount | 500,000 | 500,000 | |
7.75% Senior notes due 2022, net of unamortized debt issuance costs | 494,398 | 493,557 | |
6.125% Senior Notes due 2024 [Member] | |||
Debt Instrument | |||
Unamortized Debt Issuance Expense | (6,815) | (7,544) | $ (7,800) |
Principal amount | 400,000 | 400,000 | |
7.75% Senior notes due 2022, net of unamortized debt issuance costs | 393,185 | 392,456 | |
Revolving Credit Facility | |||
Debt Instrument | |||
Revolving credit facility | $ 0 | $ 0 |
Long-Term Debt Additional Infor
Long-Term Debt Additional Information (Details) - USD ($) | Oct. 15, 2022 | Sep. 15, 2021 | May 21, 2020 | Sep. 12, 2016 | Oct. 03, 2012 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 14, 2016 | Nov. 15, 2010 |
Debt Instrument | ||||||||||||
Cash repayment of convertible notes | $ 0 | $ 115,000,000 | ||||||||||
3.25% Convertible Note, Conversion Price | $ 85.39 | |||||||||||
Debt Instrument, Maturity Date | Sep. 15, 2021 | |||||||||||
Debt Issuance Costs, Line of Credit Arrangements, Net | $ 6,800,000 | $ 8,800,000 | ||||||||||
3.25% Convertible Senior Notes due 2016 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
3.25% Convertible Note, Conversion Price | $ 42.40 | |||||||||||
1.125% Convertible Senior Notes due 2021 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 1.125% | |||||||||||
Debt Instrument, Issuance Date | Sep. 12, 2016 | |||||||||||
6.125% Senior Notes due 2024 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | |||||||||||
Debt Instrument, Issuance Date | Sep. 12, 2016 | |||||||||||
7.75% Senior Notes due 2022 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | |||||||||||
Debt Instrument, Issuance Date | Oct. 3, 2012 | |||||||||||
Debt Instrument, Maturity Date | Oct. 15, 2022 | |||||||||||
Payments of Debt Issuance Costs | $ 11,000,000 | |||||||||||
Revolving Credit Facility | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Expiration Date | May 21, 2020 | |||||||||||
Minimum [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity ($) | 700,000,000 | |||||||||||
Maximum [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity ($) | 1,000,000,000 | $ 950,000,000 | ||||||||||
Maximum Borrowing Base [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity ($) | $ 1,000,000,000 | |||||||||||
First Payment | 1.125% Convertible Senior Notes due 2021 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | March 15 | |||||||||||
First Payment | 6.125% Senior Notes due 2024 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | March 15 | |||||||||||
First Payment | 7.75% Senior Notes due 2022 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | April 15 | |||||||||||
Second Payment | 1.125% Convertible Senior Notes due 2021 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | September 15 | |||||||||||
Second Payment | 6.125% Senior Notes due 2024 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | September 15 | |||||||||||
Second Payment | 7.75% Senior Notes due 2022 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Debt Instrument, Frequency of Periodic Payment | October 15 | |||||||||||
Revolving Credit Facility | ||||||||||||
Debt Instrument | ||||||||||||
Long-term Line of Credit | $ 0 | 0 | ||||||||||
1.125% Convertible Senior Notes due 2021 [Member] | ||||||||||||
Debt Instrument | ||||||||||||
3.25% convertible senior notes fair value | 200,000,000 | 200,000,000 | ||||||||||
Liability component of gross proceeds of Convertible Notes | 160,500,000 | |||||||||||
Unamortized Debt Issuance Expense | $ (3,859,000) | $ (4,584,000) | $ (4,800,000) | |||||||||
Debt Instrument, Interest Rate, Effective Percentage | 5.80% | |||||||||||
Alternate Base Rate Option [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Interest Rate at Period End | 1.25% | |||||||||||
LIBOR Option [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Interest Rate at Period End | 2.25% | |||||||||||
Unused Commitment Fee [Member] | ||||||||||||
Debt Instrument | ||||||||||||
Line of Credit Facility, Interest Rate at Period End | 0.50% |
Other Accrued Expenses Other 62
Other Accrued Expenses Other Accrued Expenses (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Other Accrued Expenses [Abstract] | ||
Accrued Employee Benefits, Current | $ 14,401 | $ 22,282 |
Asset Retirement Obligation, Current | (13,128) | (9,775) |
Other Accrued Liabilities | 5,922 | 6,568 |
Other Accrued Liabilities, Noncurrent | $ 33,451 | $ 38,625 |
Capital Leases Capital Leases (
Capital Leases Capital Leases (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Capital Leased Assets [Line Items] | ||
Vehicles | $ 6,301 | $ 2,975 |
Accumulated Depreciation | (1,435) | (776) |
Capital Leased Assets, Net | $ 4,866 | $ 2,199 |
Capital Leases Minimum Lease Pa
Capital Leases Minimum Lease Payments (Details) $ in Thousands | Sep. 30, 2017USD ($) |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 5,582 |
Executory Costs | (258) |
Amount representing interest | (615) |
Present Value of Net Minimum Payments | 4,709 |
Short-term Capital Lease Obligations | 1,768 |
Long-Term Capital Lease Obligations | 2,941 |
Total Capital Lease Obligations | 4,709 |
2,017 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 2,207 |
2,018 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 1,617 |
2,019 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 1,758 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis | |||||
Balance at beginning of period, January 1, 2016 | $ 92,387 | ||||
Obligations incurred with development activities | 3,296 | ||||
Accretion expense | $ 1,472 | $ 1,777 | 4,906 | $ 5,400 | |
Asset Retirement Obligation, Revision of Estimate | 155 | ||||
Obligations discharged asset retirements | (8,929) | ||||
Balance end of period, September 30, 2017 | 91,815 | 91,815 | |||
Disposal Group, Including Discontinued Operation, Other Liabilities | (499) | (499) | |||
Less current portion | (13,128) | (13,128) | $ (9,775) | ||
Long-term portion | $ 78,188 | $ 78,188 | $ 82,612 |
Commitments and Contingencies66
Commitments and Contingencies Commitments and Contigencies (Details) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2017USD ($)MMcfMBbls | Sep. 30, 2017USD ($)MMcfMBbls | |
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 308,131 | 308,131 |
Dollar Commitment ($ in thousands) | $ | $ 261,851 | $ 261,851 |
Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 34,714 | 34,714 |
Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 15,975 | 15,975 |
Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 209,922 | 209,922 |
Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 47,520 | 47,520 |
First Year Commitment [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 24,455 | 24,455 |
Dollar Commitment ($ in thousands) | $ | $ 18,410 | $ 18,410 |
First Year Commitment [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,117 | 7,117 |
First Year Commitment [Member] | Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,738 | 2,738 |
First Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 0 | 0 |
First Year Commitment [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 14,600 | 14,600 |
Second Year Commitment [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 41,215 | 41,215 |
Dollar Commitment ($ in thousands) | $ | $ 35,170 | $ 35,170 |
Second Year Commitment [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,117 | 7,117 |
Second Year Commitment [Member] | Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,738 | 2,738 |
Second Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 16,760 | 16,760 |
Second Year Commitment [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 14,600 | 14,600 |
Third Year Commitment [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 55,371 | 55,371 |
Dollar Commitment ($ in thousands) | $ | $ 44,949 | $ 44,949 |
Third Year Commitment [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,136 | 7,136 |
Third Year Commitment [Member] | Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,745 | 2,745 |
Third Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 30,850 | 30,850 |
Third Year Commitment [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 14,640 | 14,640 |
Fourth Year Commitment [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 44,560 | 44,560 |
Dollar Commitment ($ in thousands) | $ | $ 33,776 | $ 33,776 |
Fourth Year Commitment [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,117 | 7,117 |
Fourth Year Commitment [Member] | Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 2,738 | 2,738 |
Fourth Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,025 | 31,025 |
Fourth Year Commitment [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 3,680 | 3,680 |
commitments 5 years and beyond [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 142,530 | 142,530 |
Dollar Commitment ($ in thousands) | $ | $ 129,546 | $ 129,546 |
commitments 5 years and beyond [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,227 | 6,227 |
commitments 5 years and beyond [Member] | Utica Shale | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 5,016 | 5,016 |
commitments 5 years and beyond [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 131,287 | 131,287 |
commitments 5 years and beyond [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 0 | 0 |
Supply Contract Expiration Date [Member] | Appalachiain Basin | ||
Supply Commitment | ||
Supply Commitments Contract Expiration Date | Aug. 31, 2022 | |
Supply Contract Expiration Date [Member] | Utica Shale | ||
Supply Commitment | ||
Supply Commitments Contract Expiration Date | Jul. 22, 2023 | |
Supply Contract Expiration Date [Member] | Wattenberg Field | ||
Supply Commitment | ||
Supply Commitments Contract Expiration Date | Mar. 31, 2026 | |
Supply Contract Expiration Date [Member] | Delaware Basin [Member] | ||
Supply Commitment | ||
Supply Commitments Contract Expiration Date | Dec. 31, 2020 | |
Crude Oil [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,638 | 6,638 |
Crude Oil [Member] | First Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 2,413 | 2,413 |
Crude Oil [Member] | Second Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 2,413 | 2,413 |
Crude Oil [Member] | Third Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 1,812 | 1,812 |
Crude Oil [Member] | Fourth Year Commitment [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 0 | 0 |
Crude Oil [Member] | commitments 5 years and beyond [Member] | Wattenberg Field | ||
Supply Commitment | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 0 | 0 |
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Wattenberg Field | ||
Supply Commitment | ||
Supply Commitments Contract Expiration Date | Jun. 30, 2020 | |
First facilities agreement with midstream provider [Member] | ||
Supply Commitment | ||
incremental volume commitment | 51.5 | |
Second facilities agreement with midstream provider [Member] | ||
Supply Commitment | ||
incremental volume commitment | 33.5 |
Commitments and Contingencies A
Commitments and Contingencies Additional information (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($)MMcf | Sep. 30, 2016USD ($) | |
Loss Contingencies [Line Items] | ||||
Transportation, gathering and processing expenses | $ 9,794 | $ 5,048 | $ 22,184 | $ 13,554 |
Loss Contingency, Actions Taken by Court, Arbitrator or Mediator | A consent decree was signed by all parties on October 31, 2017 and is subject to a 30-day comment period in which it will be publicly published in the Federal Register. The consent decree provides that we will implement changes to our design, operation, and maintenance of most of our field-wide storage tank systems to enhance our emission management in the DJ Basin. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. We voluntarily included in the consent decree approximately 40 additional facilities associated with our pending acquisition of additional assets in the basin. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects); (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. Certain expenditures for the injunctive relief are believed to have been incurred in 2016 and 2017, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Although we believe the consent decree will be approved by the court following the comment period, this cannot be guaranteed. | |||
First facilities agreement with midstream provider [Member] | ||||
Loss Contingencies [Line Items] | ||||
incremental volume commitment | MMcf | 51.5 | |||
Utica Shale natural gas and Wattenberg Field crude oil [Member] | ||||
Loss Contingencies [Line Items] | ||||
Transportation, gathering and processing expenses | $ 2,600 | $ 2,600 | $ 7,400 | $ 7,200 |
Common Stock Sale of Common Sto
Common Stock Sale of Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Class of Stock [Line Items] | |||
Common stock, par value | $ 0.01 | $ 0.01 | |
Proceeds from issuance of equity, net of issuance costs | $ 0 | $ 855,072 | |
Common shares - par value | 659 | $ 657 | |
Additional paid-in capital | 2,500,532 | $ 2,489,557 | |
Repayments of Convertible Debt | $ 0 | $ 115,000 | |
Debt Instrument, Convertible, Conversion Price | $ 85.39 |
Share Based Compensation Summar
Share Based Compensation Summary (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs | ||||
Stock-based compensation expense | $ 4,761 | $ 4,079 | $ 14,587 | $ 15,205 |
Income tax benefit | (1,781) | (1,552) | (5,457) | (5,786) |
Net stock-based compensation expense | $ 2,980 | $ 2,527 | $ 9,130 | $ 9,419 |
SARs Fair Value Assumptions (De
SARs Fair Value Assumptions (Details) - Stock Appreciation Rights (SARs) - $ / shares | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Expected term of award | 6 years | 6 years |
Risk-free interest rate | 2.00% | 1.80% |
Expected Volatility | 53.30% | 54.50% |
Granted | $ 38.58 | $ 26.96 |
Schedule of Changes in SARs (De
Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | |
Number of SARs | |||
Outstanding beginning of year, January 1, | 244,078 | ||
Awarded | 54,142 | ||
Outstanding at September 30, | 298,220 | 244,078 | |
Exercisable at September 30, | 186,248 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price | |||
Outstanding beginning of year, January 1, | $ 41.36 | ||
Awarded | 74.57 | ||
Outstanding at September 30, | $ 47.39 | $ 41.36 | |
Exercisable at September 30, | $ 39.38 | ||
Weighted-Average Remaining Contractual Term (in years) | |||
Outstanding at September 30, | 6 years 8 months 12 days | 6 years 10 months 25 days | |
Exercisable at September 30, | 5 years 7 months 7 days | ||
Share based compesation aggregate intrinsic value | |||
Outstanding beginning of year, January 1, | $ 2,043 | $ 7,620 | $ 2,043 |
Outstanding at September 30, | $ 2,043 | $ 7,620 | |
Exercisable at September 30, | 1,867 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 2,300 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 months 25 days |
Schedule of Changes in Restrict
Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. | |
Number of Shares | ||
Outstanding beginning of year, January 1, | 479,642 | |
Granted | 260,019 | |
Vested | (206,242) | |
Forfeited | (7,990) | |
Outstanding at September 30, | 525,429 | |
Weighted-Average Grant-Date Fair Value | ||
Outstanding at beginning of year, January 1, | $ 56.09 | |
Granted | 66 | $ 57.12 |
Vested | 56.44 | |
Forfeited | 64.32 | |
Outstanding at June 30, | $ 60.73 | |
Total intrinsic value of time based awards vested | $ 13,266 | $ 14,675 |
Total intrinsic value of time-based awards non-vested | $ 25,762 | $ 35,079 |
Market price per common share as of June 30, | $ 49.03 | $ 67.06 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 22,000 | |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 months 25 days |
Restricted Stock - Market Based
Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards - $ / shares | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Expected term of award | 3 years | 3 years |
Risk-free interest rate | 1.40% | 1.20% |
Expected Volatility | 51.40% | 52.30% |
Granted | $ 94.02 | $ 72.54 |
Schedule of Changes in Restri74
Schedule of Changes in Restricted Stock - Market Based Awards (Details) - Restricted Stock - Market Based Awards - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Vested and expected to vest at September 30, | $ 0 | $ 1,174 |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. | |
Time based shares granted to executives | 28,069 | |
Number of Shares | ||
Outstanding beginning of year, January 1, | 48,420 | |
Granted | 28,069 | |
Outstanding at September 30, | 76,489 | |
Weighted-Average Grant-Date Fair Value | ||
Outstanding at beginning of year, January 1, | $ 64.97 | |
Granted | 94.02 | $ 72.54 |
Outstanding at June 30, | $ 75.63 | |
Total intrinsic value of market-based awards non-vested | $ 3,750 | $ 5,670 |
Market price per common share as of June 30, | $ 49.03 | $ 67.06 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 2,900 | |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 months 25 days |
Common Stock Preferred Stock (D
Common Stock Preferred Stock (Details) - shares | Sep. 30, 2017 | Dec. 31, 2016 | Jun. 23, 2008 |
Share-based Compensation Arrangement by Share-based Payment Award | |||
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 | |
Preferred Stock, Shares Issued | 0 | 0 | |
Preferred Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Preferred Stock, Shares Authorized | 50,000,000 | ||
Preferred Stock, Shares Issued | 0 |
Common Stock Treasury Shares (D
Common Stock Treasury Shares (Details) - shares | 9 Months Ended | ||
Sep. 30, 2017 | Dec. 31, 2016 | Jun. 29, 2010 | |
Share-based Compensation Arrangement by Share-based Payment Award | |||
Common stock, shares authorized | 150,000,000 | 150,000,000 | 3,000,000 |
Treasury stock acquired, and available for reissuance | 10,397 | ||
Common Stock, Shares Held in Employee Trust, Shares | 18,366 | ||
Treasury Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Treasury stock acquired, and available for reissuance | 41,523 | ||
Treasury Stock, Shares, Acquired | 80,572 | ||
Treasury stock acquired and reissued | 49,446 |
Earnings Per Share (Details)
Earnings Per Share (Details) | Nov. 15, 2010shares$ / shares | Sep. 30, 2017shares | Sep. 30, 2016shares | Sep. 30, 2017shares | Sep. 30, 2016shares | Dec. 31, 2016shares$ / shares |
Reconciliation of Weighted-Average Diluted Shares Outstanding | ||||||
Weighted average common shares outstanding - basic | 65,865,000 | 48,839,000 | 65,825,000 | 45,741,000 | ||
Anti-dilutive Effect | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 636,000 | 757,000 | 667,000 | 1,153,000 | ||
Convertible Senior Note Due 2016 | ||||||
3.25% Convertible Note, Shares To Be Received Upon Conversion (in thousands) | 2,300,000 | |||||
3.25% Convertible Note, Conversion Price | $ / shares | $ 85.39 | |||||
Restricted stock | ||||||
Anti-dilutive Effect | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 588,000 | 660,000 | 585,000 | 705,000 | ||
3.25% Convertible Note [Member] | ||||||
Anti-dilutive Effect | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 0 | 0 | 0 | 345,000 | ||
Other equity-based awards | ||||||
Anti-dilutive Effect | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 48,000 | 97,000 | 82,000 | 103,000 | ||
3.25% Convertible Senior Notes due 2016 [Member] | ||||||
Convertible Senior Note Due 2016 | ||||||
3.25% Convertible Note, Shares To Be Received Upon Conversion (in thousands) | 2,700,000 | |||||
3.25% Convertible Note, Conversion Price | $ / shares | $ 42.40 |
Subsidiary Guarantor Condensed
Subsidiary Guarantor Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Assets, Current | $ 334,702 | $ 399,825 |
Properties and equipment, net | 3,882,700 | 4,002,994 |
Intercompany Receivables | 0 | 0 |
Investments in subsidiaries | 0 | 0 |
Goodwill | 0 | 62,041 |
Assets, Noncurrent | 89,885 | 20,982 |
Total Assets | 4,307,287 | 4,485,842 |
Liabilities, Current | 373,788 | 270,578 |
Intercompany Payable | 0 | 0 |
Long-term debt | 1,051,571 | 1,043,954 |
Other noncurrent liabilities | 455,326 | 548,556 |
Total stockholders' equity | 2,426,602 | 2,622,754 |
Total Liabilities and Stockholders' Equity | 4,307,287 | 4,485,842 |
Parent Company [Member] | ||
Assets, Current | 299,239 | 387,309 |
Properties and equipment, net | 1,911,759 | 1,884,147 |
Intercompany Receivables | 199,871 | 9,415 |
Investments in subsidiaries | 1,467,623 | 1,765,092 |
Goodwill | 0 | |
Assets, Noncurrent | 89,245 | 20,811 |
Total Assets | 3,967,737 | 4,066,774 |
Liabilities, Current | 310,997 | 235,121 |
Intercompany Payable | 0 | 0 |
Long-term debt | 1,051,571 | 1,043,954 |
Other noncurrent liabilities | 178,567 | 164,945 |
Total stockholders' equity | 2,426,602 | 2,622,754 |
Total Liabilities and Stockholders' Equity | 3,967,737 | 4,066,774 |
Guarantor Subsidiaries [Member] | ||
Assets, Current | 35,463 | 12,516 |
Properties and equipment, net | 1,970,941 | 2,118,847 |
Intercompany Receivables | 0 | 0 |
Investments in subsidiaries | 0 | 0 |
Goodwill | 62,041 | |
Assets, Noncurrent | 640 | 171 |
Total Assets | 2,007,044 | 2,193,575 |
Liabilities, Current | 62,791 | 35,457 |
Intercompany Payable | 199,871 | 9,415 |
Long-term debt | 0 | 0 |
Other noncurrent liabilities | 276,759 | 383,611 |
Total stockholders' equity | 1,467,623 | 1,765,092 |
Total Liabilities and Stockholders' Equity | 2,007,044 | 2,193,575 |
Consolidation, Eliminations [Member] | ||
Assets, Current | 0 | 0 |
Properties and equipment, net | 0 | 0 |
Intercompany Receivables | (199,871) | (9,415) |
Investments in subsidiaries | (1,467,623) | (1,765,092) |
Goodwill | 0 | |
Assets, Noncurrent | 0 | 0 |
Total Assets | (1,667,494) | (1,774,507) |
Liabilities, Current | 0 | 0 |
Intercompany Payable | (199,871) | (9,415) |
Long-term debt | 0 | 0 |
Other noncurrent liabilities | 0 | 0 |
Total stockholders' equity | (1,467,623) | (1,765,092) |
Total Liabilities and Stockholders' Equity | $ (1,667,494) | $ (1,774,507) |
Subsidiary Guarantor Condense79
Subsidiary Guarantor Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Revenues | $ 183,235 | $ 163,890 | $ 732,100 | $ 274,818 |
Operating Costs and Expenses | 55,020 | 144,828 | ||
General and administrative expense | 29,299 | 32,510 | 85,145 | 78,868 |
Exploration, geologic, and geophysical expense | 41,908 | 241 | 43,895 | 688 |
Depreciation, depletion and amortization | 125,238 | 112,927 | 360,567 | 317,329 |
Impairment of Oil and Gas Properties | 252,740 | 933 | 282,499 | 3,072 |
Impairment of goodwill | 75,121 | 0 | 75,121 | 0 |
Provision for uncollectible notes receivable | 0 | (700) | (40,203) | 44,038 |
Interest Income (Expense), Net | (18,796) | (56,872) | ||
Loss before income taxes | (414,887) | (35,341) | (276,624) | (302,487) |
Income tax benefit | 122,350 | 12,032 | 71,483 | 112,198 |
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | ||
Net loss | (292,537) | $ (23,309) | (205,141) | $ (190,289) |
Consolidation, Eliminations [Member] | ||||
Revenues | 0 | 0 | ||
Operating Costs and Expenses | 0 | 0 | ||
General and administrative expense | 0 | 0 | ||
Exploration, geologic, and geophysical expense | 0 | 0 | ||
Depreciation, depletion and amortization | 0 | 0 | ||
Impairment of Oil and Gas Properties | 0 | 0 | ||
Impairment of goodwill | 0 | 0 | ||
Provision for uncollectible notes receivable | 0 | |||
Interest Income (Expense), Net | 0 | 0 | ||
Loss before income taxes | 0 | 0 | ||
Income tax benefit | 0 | 0 | ||
Income (Loss) from Subsidiaries, Net of Tax | 277,572 | 297,469 | ||
Net loss | 277,572 | 297,469 | ||
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
Revenues | 33,220 | 74,998 | ||
Operating Costs and Expenses | 13,129 | 26,049 | ||
General and administrative expense | 3,092 | 8,792 | ||
Exploration, geologic, and geophysical expense | 41,691 | 43,151 | ||
Depreciation, depletion and amortization | 18,615 | 43,479 | ||
Impairment of Oil and Gas Properties | 251,592 | 280,217 | ||
Impairment of goodwill | 75,121 | 75,121 | ||
Provision for uncollectible notes receivable | 0 | |||
Interest Income (Expense), Net | 372 | 685 | ||
Loss before income taxes | (369,648) | (401,126) | ||
Income tax benefit | 92,076 | 103,657 | ||
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | ||
Net loss | (277,572) | (297,469) | ||
Parent Company [Member] | Reportable Legal Entities [Member] | ||||
Revenues | 150,015 | 657,102 | ||
Operating Costs and Expenses | 41,891 | 118,779 | ||
General and administrative expense | 26,207 | 76,353 | ||
Exploration, geologic, and geophysical expense | 217 | 744 | ||
Depreciation, depletion and amortization | 106,623 | 317,088 | ||
Impairment of Oil and Gas Properties | 1,148 | 2,282 | ||
Impairment of goodwill | 0 | 0 | ||
Provision for uncollectible notes receivable | (40,203) | |||
Interest Income (Expense), Net | (19,168) | (57,557) | ||
Loss before income taxes | (45,239) | 124,502 | ||
Income tax benefit | 30,274 | (32,174) | ||
Income (Loss) from Subsidiaries, Net of Tax | (277,572) | (297,469) | ||
Net loss | $ (292,537) | $ (205,141) |
Subsidiary Guarantor Condense80
Subsidiary Guarantor Condensed Consolidating Statement of Cash Flows (Details) - USD ($) | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Net cash from operating activities | $ 411,402,000 | $ 360,831,000 |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | (528,850,000) | (352,213,000) |
Capital expenditures for other properties and equipment | (3,740,000) | (1,509,000) |
Acquisition of crude oil and natural gas properties, including final settlement adjustments | (14,482,000) | |
Proceeds from sale of properties and equipment | 3,322,000 | 4,945,000 |
Sale of promissory note | 40,203,000 | 0 |
Restricted cash | (9,250,000) | 0 |
Sale of short-term investments | 49,890,000 | 0 |
Purchases of short-term investments | (49,890,000) | 0 |
intercompany Transfer Investing Activities | 0 | |
Net cash from investing activities | (512,797,000) | (448,777,000) |
Cash flows from financing activities: | ||
Purchase of treasury shares | (5,325,000) | (5,106,000) |
Other | (951,000) | 593,000 |
Intercompany Transfers Financing Activities | 0 | |
Net cash from financing activities | (6,276,000) | 1,284,788,000 |
Net change in cash and cash equivalents | (107,671,000) | 1,196,842,000 |
Cash and cash equivalents, beginning of period | 244,100,000 | 850,000 |
Cash and cash equivalents, end of period | 136,429,000 | $ 1,197,692,000 |
Consolidation, Eliminations [Member] | ||
Net cash from operating activities | 0 | |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | 0 | |
Capital expenditures for other properties and equipment | 0 | |
Acquisition of crude oil and natural gas properties, including final settlement adjustments | 0 | |
Proceeds from sale of properties and equipment | 0 | |
Sale of promissory note | 0 | |
Restricted cash | 0 | |
Sale of short-term investments | 0 | |
Purchases of short-term investments | 0 | |
intercompany Transfer Investing Activities | 189,239,000 | |
Net cash from investing activities | 189,239,000 | |
Cash flows from financing activities: | ||
Purchase of treasury shares | 0 | |
Other | 0 | |
Intercompany Transfers Financing Activities | (189,239,000) | |
Net cash from financing activities | (189,239,000) | |
Net change in cash and cash equivalents | 0 | |
Cash and cash equivalents, beginning of period | 0 | |
Cash and cash equivalents, end of period | 0 | |
Parent Company [Member] | Reportable Legal Entities [Member] | ||
Net cash from operating activities | 382,715,000 | |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | (315,718,000) | |
Capital expenditures for other properties and equipment | (2,488,000) | |
Acquisition of crude oil and natural gas properties, including final settlement adjustments | (19,761,000) | |
Proceeds from sale of properties and equipment | 3,322,000 | |
Sale of promissory note | 40,203,000 | |
Restricted cash | (9,250,000) | |
Sale of short-term investments | 49,890,000 | |
Purchases of short-term investments | (49,890,000) | |
intercompany Transfer Investing Activities | (189,239,000) | |
Net cash from investing activities | (492,931,000) | |
Cash flows from financing activities: | ||
Purchase of treasury shares | (5,325,000) | |
Other | (906,000) | |
Intercompany Transfers Financing Activities | 0 | |
Net cash from financing activities | (6,231,000) | |
Net change in cash and cash equivalents | (116,447,000) | |
Cash and cash equivalents, beginning of period | 240,487,000 | |
Cash and cash equivalents, end of period | 124,040,000 | |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||
Net cash from operating activities | 28,687,000 | |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | (213,132,000) | |
Capital expenditures for other properties and equipment | (1,252,000) | |
Acquisition of crude oil and natural gas properties, including final settlement adjustments | 5,279,000 | |
Proceeds from sale of properties and equipment | 0 | |
Sale of promissory note | 0 | |
Restricted cash | 0 | |
Sale of short-term investments | 0 | |
Purchases of short-term investments | 0 | |
intercompany Transfer Investing Activities | 0 | |
Net cash from investing activities | (209,105,000) | |
Cash flows from financing activities: | ||
Purchase of treasury shares | 0 | |
Other | (45,000) | |
Intercompany Transfers Financing Activities | 189,239,000 | |
Net cash from financing activities | 189,194,000 | |
Net change in cash and cash equivalents | 8,776,000 | |
Cash and cash equivalents, beginning of period | 3,613,000 | |
Cash and cash equivalents, end of period | $ 12,389,000 |