Document and Entity Information
Document and Entity Information Document Document - shares | 9 Months Ended | |
Sep. 30, 2018 | Oct. 22, 2018 | |
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, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 66,080,471 | |
Smaller Reporting Company | false | |
Entity Emerging Growth Company | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 1,369 | $ 180,675 |
Accounts receivable, net | 241,155 | 197,598 |
Fair value of derivatives | 7,555 | 14,338 |
Prepaid expenses and other current assets | 6,713 | 8,613 |
Total current assets | 256,792 | 401,224 |
Properties and equipment, net | 4,309,021 | 3,933,467 |
Assets held-for-sale, net | 0 | 40,084 |
Fair value of derivatives | 3,949 | 0 |
Other assets | 31,462 | 45,116 |
Total Assets | 4,601,224 | 4,419,891 |
Current liabilities: | ||
Accounts payable | 251,081 | 150,067 |
Production tax liability | 59,539 | 37,654 |
Fair value of derivatives | 205,013 | 79,302 |
Funds held for distribution | 104,259 | 95,811 |
Accrued interest payable | 15,425 | 11,815 |
Other accrued expenses | 39,260 | 42,987 |
Total current liabilities | 674,577 | 417,636 |
Long-term debt | 1,234,733 | 1,151,932 |
Deferred income taxes | 138,963 | 191,992 |
Asset retirement obligations | 72,707 | 71,006 |
Fair value of derivatives | 61,013 | 22,343 |
Other liabilities | 76,987 | 57,333 |
Total liabilities | 2,258,980 | 1,912,242 |
Commitments and contingent liabilities | ||
Stockholders' Equity: | ||
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively | 661 | 659 |
Additional paid-in capital | 2,514,861 | 2,503,294 |
Retained earnings (deficit) | (170,126) | 6,704 |
Treasury shares - at cost, 62,265 and 55,927 as of September 30, 2018 and December 31, 2017, respectively | (3,152) | (3,008) |
Total stockholders' equity | 2,342,244 | 2,507,649 |
Total Liabilities and Stockholders' Equity | $ 4,601,224 | $ 4,419,891 |
Balance Sheet Parenthetical (Pa
Balance Sheet Parenthetical (Parentheticals) - $ / shares | Sep. 30, 2018 | Dec. 31, 2017 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Common stock, shares issued | 66,136,427 | 65,955,080 |
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 | 62,265 | 55,927 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues: | ||||
Crude oil, natural gas and NGLs sales | $ 372,439 | $ 232,733 | $ 1,003,597 | $ 636,027 |
Commodity price risk management gain (loss), net | (94,394) | (52,178) | (257,760) | 86,458 |
Other income | 2,672 | 2,680 | 8,011 | 9,615 |
Total revenues | 280,717 | 183,235 | 753,848 | 732,100 |
Costs, expenses and other: | ||||
Lease operating expenses | 33,046 | 25,353 | 94,942 | 65,170 |
Production taxes | 23,984 | 15,516 | 66,757 | 42,957 |
Transportation, gathering and processing expenses | 9,234 | 9,794 | 25,511 | 22,184 |
Exploration, geologic and geophysical expense | 1,032 | 41,908 | 4,553 | 43,895 |
Impairment of properties and equipment | 1,488 | 252,740 | 194,230 | 282,499 |
Impairment of goodwill | 0 | 75,121 | 0 | 75,121 |
General and administrative expense | 48,240 | 29,299 | 121,183 | 85,145 |
Depreciation, depletion and amortization | 147,540 | 125,238 | 409,952 | 360,567 |
Accretion of asset retirement obligations | 1,200 | 1,472 | 3,773 | 4,906 |
(Gain) loss on sale of properties and equipment | 2,118 | (62) | 3,199 | (754) |
Provision for uncollectible note receivable | 0 | 0 | 0 | 40,203 |
Other expenses | 2,711 | 2,947 | 8,187 | 10,365 |
Total cost, expenses and other | 270,593 | 579,326 | 932,287 | 951,852 |
Income (loss) from operations | 10,124 | (396,091) | (178,439) | (219,752) |
Interest expense | (17,622) | (19,275) | (52,561) | (58,359) |
Interest income | 188 | 479 | 405 | 1,487 |
Income (loss) before income taxes | (7,310) | (414,887) | (230,595) | (276,624) |
Income tax (expense) benefit | 3,876 | 122,350 | 53,765 | 71,483 |
Net income (loss) | $ (3,434) | $ (292,537) | $ (176,830) | $ (205,141) |
Earnings per share: | ||||
Basic | $ (0.05) | $ (4.44) | $ (2.68) | $ (3.12) |
Diluted | $ (0.05) | $ (4.44) | $ (2.68) | $ (3.12) |
Weighted-average common shares outstanding | ||||
Basic | 66,073 | 65,865 | 66,032 | 65,825 |
Diluted | 66,073 | 65,865 | 66,032 | 65,825 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Net income (loss) | $ (176,830) | $ (205,141) |
Net income (loss) | (176,830) | (205,141) |
Adjustments to net income (loss) to reconcile to net cash provided by operating activities: | ||
Net change in fair value of unsettled derivatives | 167,218 | (64,307) |
Depreciation, depletion and amortization | 409,952 | 360,567 |
Impairment of properties and equipment | 194,230 | 282,499 |
Impairment of goodwill | 0 | 75,121 |
Exploratory dry hole costs | 0 | 41,187 |
Provision for uncollectible note receivable | 0 | (40,203) |
Accretion of asset retirement obligations | 3,773 | 4,906 |
Non-cash stock-based compensation | 16,357 | 14,587 |
(Gain) loss on sale of properties and equipment | 3,199 | (754) |
Amortization of debt discount and issuance costs | 9,454 | 9,628 |
Deferred income taxes | (53,029) | (71,529) |
Other | 1,025 | 986 |
Changes in assets and liabilities | 2,485 | 13,105 |
Net cash from operating activities | 577,834 | 420,652 |
Cash flows from investing activities: | ||
Capital expenditures for development of crude oil and natural gas properties | (685,549) | (528,850) |
Capital expenditures for other properties and equipment | (3,739) | (3,740) |
Acquisition of crude oil and natural gas properties, including settlement adjustments | (181,572) | (14,482) |
Proceeds from sale of properties and equipment | 2,443 | 3,322 |
Proceeds from divestiture | 43,493 | 0 |
Proceeds from Sale of Notes Receivable | 0 | 40,203 |
Restricted cash | 1,249 | (9,250) |
Proceeds from Sale of Short-term Investments | 0 | 49,890 |
Purchases of short-term investments | 0 | (49,890) |
Net cash from investing activities | (823,675) | (512,797) |
Cash flows from financing activities: | ||
Proceeds from revolving credit facility | 629,000 | 0 |
Repayment of revolving credit facility | (554,000) | 0 |
Payments of Debt Issuance Costs | (4,086) | 0 |
Purchase of treasury shares | 4,700 | 5,325 |
Other | (928) | (951) |
Net cash from financing activities | 65,286 | (6,276) |
Net change in cash, cash equivalents, and restricted cash | (180,555) | (98,421) |
Cash, cash equivalents and restricted cash, beginning of period | 189,925 | 244,100 |
Cash, cash equivalents and restricted cash, end of period | 9,370 | 145,679 |
Cash payments (receipts) for: | ||
Interest, net of capitalized interest | 39,470 | 45,719 |
Income taxes | (6,707) | (2,623) |
Non-cash investing and financing activities: | ||
Change in accounts payable related to purchases of properties and equipment | 91,444 | 89,974 |
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | 6,720 | 3,357 |
Purchase of properties and equipment under capital leases | $ 1,253 | $ 3,363 |
Consolidated Statement of Equit
Consolidated Statement of Equity (Statement) - USD ($) $ in Thousands | 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 | (65,955,080) | (55,927) | ||||
Issuance of stock awards, net of forfeitures | 181,347 | |||||
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract] | ||||||
Purchase of treasury shares | (90,465) | |||||
Issuance of treasury shares | 0 | 86,701 | ||||
Non-employee directors' deferred compensation plan | (2,574) | |||||
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017 | $ 2,507,649 | $ 659 | $ 2,503,294 | $ 6,704 | $ (3,008) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Purchase of treasury shares | $ (4,700) | (4,700) | (4,700) | |||
Issuance of stock awards, net of forfeitures | 0 | (2) | (2) | |||
Share-based Compensation expense | 16,357 | 16,357 | 16,357 | |||
Issuance of treasury shares | 0 | 0 | (4,698) | (4,698) | ||
Non-employee directors' deferred compensation plan | (142) | 0 | (142) | |||
Net income (loss) | $ (176,830) | (176,830) | (176,830) | |||
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2018 | 2,342,244 | $ 661 | 2,514,861 | $ (170,126) | $ (3,152) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Stockholders' Equity, Other | $ (90) | $ (90) | ||||
Shares, Issued | (66,136,427) | (62,265) |
NATURE OF OPERATIONS AND BASIS
NATURE OF OPERATIONS AND BASIS OF PRESENTATION | 9 Months Ended |
Sep. 30, 2018 | |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract] | |
Nature of Operations | NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of September 30, 2018 , we owned an interest in approximately 3,000 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. 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 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, 2017 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 2017 Form 10-K. Our results of operations and cash flows for the nine months ended September 30, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period. |
Recent Accounting Standards
Recent Accounting Standards | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Recently Adopted Accounting Standards In May 2014, the Financial Accounting Standards Board ("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 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. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, 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 the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. 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 the 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. Adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at September 30, 2018 and 2017 and December 31, 2017 , which sum to the total of cash, cash equivalents and restricted cash in the condensed consolidated statements of cash flows: September 30, 2018 December 31, 2017 September 30, 2017 (in thousands) Cash and cash equivalents $ 1,369 $ 180,675 $ 136,429 Restricted cash 8,001 9,250 9,250 Cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows $ 9,370 $ 189,925 $ 145,679 Restricted cash is included in other assets on the condensed consolidated balance sheets at September 30, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. 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 effective July 1, 2018. Adoption of this standard did not have an impact on our condensed consolidated financial statements or related disclosures. Recently Issued Accounting Standards In February 2016, the FASB issued an accounting update and subsequent amendments 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. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are continuing to assess the full effect the guidance will have on our existing accounting policies and our condensed consolidated financial statements, and we expect there will be an increase in assets and liabilities on our condensed consolidated balance sheets at adoption due to the recording of right-of-use assets and corresponding lease liabilities. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2018, the FASB issued an accounting update for fair value disclosures that removes or modifies current disclosures and adds additional disclosures. The update to the guidance is the result of the FASB's test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. The guidance for the additional disclosures is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. |
Description of New Accounting Pronouncements Not yet Adopted [Text Block] | In February 2016, the FASB issued an accounting update and subsequent amendments 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. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are continuing to assess the full effect the guidance will have on our existing accounting policies and our condensed consolidated financial statements, and we expect there will be an increase in assets and liabilities on our condensed consolidated balance sheets at adoption due to the recording of right-of-use assets and corresponding lease liabilities. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2018, the FASB issued an accounting update for fair value disclosures that removes or modifies current disclosures and adds additional disclosures. The update to the guidance is the result of the FASB's test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. The guidance for the additional disclosures is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. |
Business Combination Business C
Business Combination Business Combinations (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | BUSINESS COMBINATION In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Asset Acquisition") for approximately $200.0 million in cash, after post-closing adjustments, including $21.0 million deposited into an escrow account in September 2017. The $21.0 million deposit was included in other assets on our December 31, 2017 condensed consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations and 24 operated horizontal wells that were either drilled uncompleted wells ("DUCs") or in-process wells at the time of closing. The final purchase price and allocation of the assets acquired and the liabilities assumed in the acquisition are presented below. Adjustments made subsequent to the preliminary purchase price stem from final settlement of the proceeds from operating activities and additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and current liabilities assumed. Such adjustments primarily relate to sales, operating expenses and capital costs from the effective date through closing. The details of the final purchase price and allocation of the purchase price for the transaction, are presented below (in thousands): September 30, 2018 Acquisition costs: Cash $ 168,560 Deposit made in prior period 21,000 Total cash consideration 189,560 Other purchase price adjustments 10,422 Total acquisition costs $ 199,982 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 468 Crude oil and natural gas properties - proved 205,834 Other assets 2,796 Total assets acquired 209,098 Liabilities assumed: Current liabilities (4,429 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,116 ) Total identifiable net assets acquired $ 199,982 This transaction was accounted for under the acquisition method. Accordingly, we conducted assessments of the 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. 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. The allocation of the value to the underlying leases also requires significant judgment and is 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. The results of operations for the Bayswater Asset Acquisition for the three and nine months ended September 30, 2018 have been included in our condensed consolidated financial statements, including approximately $19.8 million and $41.6 million , respectively, of total revenue, $11.6 million and $23.6 million , respectively, of income from operations and $0.18 and $0.36 , respectively, of diluted earnings per share. Pro forma results of operations for the Bayswater Asset Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our condensed consolidated financial statements for the three and nine months ended September 30, 2017 . |
Revenue Recognition (Notes)
Revenue Recognition (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Revenue from Contract with Customer [Text Block] | REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $2.9 million and $8.2 million in the three and nine months ended September 30, 2017 , respectively, with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for the three and nine months ended September 30, 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three and nine months ended September 30, 2018 and 2017 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the three and nine months ended September 30, 2018 and 2017 (in thousands): Three Months Ended September 30, Nine Months Ended September 30, Revenue by Commodity and Operating Region 2018 2017 (1) Percentage Change 2018 2017 (1) Percentage Change Crude oil Wattenberg Field $ 216,346 $ 134,785 60.5 % $ 576,645 $ 369,231 56.2 % Delaware Basin 68,341 19,654 247.7 % 184,357 49,519 272.3 % Utica Shale (2) — 2,581 (100.0 )% 2,696 10,067 (73.2 )% Total $ 284,687 $ 157,020 81.3 % $ 763,698 $ 428,817 78.1 % Natural gas Wattenberg Field $ 27,762 $ 32,919 (15.7 )% $ 80,174 $ 99,537 (19.5 )% Delaware Basin 6,994 7,627 (8.3 )% 22,145 12,863 72.2 % Utica Shale (2) — 910 (100.0 )% 1,109 4,330 (74.4 )% Total $ 34,756 $ 41,456 (16.2 )% $ 103,428 $ 116,730 (11.4 )% NGLs Wattenberg Field $ 36,758 $ 27,352 34.4 % $ 95,799 $ 74,594 28.4 % Delaware Basin 16,238 5,887 175.8 % 39,832 12,513 218.3 % Utica Shale (2) — 1,018 (100.0 )% 840 3,373 (75.1 )% Total $ 52,996 $ 34,257 54.7 % $ 136,471 $ 90,480 50.8 % Revenue by Operating Region Wattenberg Field $ 280,866 $ 195,056 44.0 % $ 752,618 $ 543,362 38.5 % Delaware Basin 91,573 33,168 176.1 % 246,334 74,895 228.9 % Utica Shale (2) — 4,509 (100.0 )% 4,645 17,770 (73.9 )% Total $ 372,439 $ 232,733 60.0 % $ 1,003,597 $ 636,027 57.8 % ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for the three and nine months ended September 30, 2017 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase/purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the nine months ended September 30, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,217 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,024 ) Ending balance, September 30, 2018 $ 2,939 Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at September 30, 2018 and December 31, 2017 was $199.5 million and $154.3 million , respectively. We did not record an allowance for doubtful accounts for these receivables at September 30, 2018 or December 31, 2017 . |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | In May 2014, the Financial Accounting Standards Board ("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 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. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, 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 the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. 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 the 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. Adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at September 30, 2018 and 2017 and December 31, 2017 , which sum to the total of cash, cash equivalents and restricted cash in the condensed consolidated statements of cash flows: September 30, 2018 December 31, 2017 September 30, 2017 (in thousands) Cash and cash equivalents $ 1,369 $ 180,675 $ 136,429 Restricted cash 8,001 9,250 9,250 Cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows $ 9,370 $ 189,925 $ 145,679 Restricted cash is included in other assets on the condensed consolidated balance sheets at September 30, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. 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 effective July 1, 2018. Adoption of this standard did not have an impact on our condensed consolidated financial statements or related disclosures. On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $2.9 million and $8.2 million in the three and nine months ended September 30, 2017 , respectively, with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for the three and nine months ended September 30, 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three and nine months ended September 30, 2018 and 2017 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 9 Months Ended |
Sep. 30, 2018 | |
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 of the hierarchy. Our collars and propane fixed-price swaps are included in Level 3 of the hierarchy. Our basis swaps are included in Level 2 and Level 3 of the hierarchy. 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, 2018 December 31, 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 5,843 $ 5,661 $ 11,504 $ 12,949 $ 1,389 $ 14,338 Total liabilities (231,503 ) (34,523 ) (266,026 ) (90,569 ) (11,076 ) (101,645 ) Net liability $ (225,660 ) $ (28,862 ) $ (254,522 ) $ (77,620 ) $ (9,687 ) $ (87,307 ) 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, 2018 2017 2018 2017 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (19,100 ) $ 8,619 $ (9,687 ) $ (9,574 ) Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (16,175 ) (14,075 ) (23,029 ) 8,547 Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net 6,413 (1,013 ) 3,854 (5,442 ) Fair value of Level 3 instruments, net liability end of period $ (28,862 ) $ (6,469 ) $ (28,862 ) $ (6,469 ) 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 $ (7,451 ) $ (8,711 ) $ (4,229 ) $ (583 ) 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 proved crude oil and natural gas properties 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 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: As of September 30, 2018 As of December 31, 2017 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) (in millions) Senior notes: 2021 Convertible Notes $ 194.2 97.1 % $ 195.6 97.8 % 2024 Senior Notes 393.8 98.5 % 416.0 104.0 % 2026 Senior Notes 570.8 95.1 % 616.5 102.8 % 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. 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, 2018 , taking into account the estimated likelihood of nonperformance. Note Receivable. In 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 . We regularly analyzed the Promissory Note for evidence of collectibility, 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. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017. 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, 2018 and December 31, 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. |
Derivative Financial Instrument
Derivative Financial Instruments | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 , we had derivative instruments, which were comprised of collars, fixed-price swaps and basis protection swaps, in place for a portion of our anticipated 2018, 2019 and 2020 production. 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. As of September 30, 2018 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu Propane - MBbls) Weighted- Average Contract Price Fair Value September 30, 2018 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2018 528 $ 45.59 $ 56.82 2,968 $ 52.23 $ (69,943 ) 2019 2,600 56.54 68.13 8,400 53.86 (157,085 ) 2020 3,600 55.00 71.68 5,000 62.07 (30,034 ) Total Crude Oil 6,728 16,368 $ (257,062 ) Natural Gas NYMEX 2018 120 $ 3.00 $ 3.90 14,145 $ 2.93 $ (1,504 ) 2019 — — — 8,004 2.78 (15 ) Dominion South 2018 — — — 94 2.12 6 2019 — — — 121 2.13 7 Columbia 2018 — — — 3 2.40 $ — 2019 — — — 3 2.40 — Total Natural Gas 120 22,370 $ (1,506 ) Basis Protection - Crude Oil Midland Cushing 2018 — $ — $ — 182 $ (0.10 ) $ 1,713 Total Basis Protection - Crude Oil — 182 $ 1,713 Basis Protection - Natural Gas CIG 2018 — $ — $ — 9,806 $ (0.42 ) $ 3,537 2019 — — — 7,924 (0.88 ) (908 ) Waha 2018 — — — 1,713 (0.50 ) 1,862 Total Basis Protection - Natural Gas — 19,443 $ 4,491 Propane Mont Belvieu 2018 — $ — $ — 167 $ 33.97 $ (1,938 ) Total Propane — 167 $ (1,938 ) Rollfactor (2) Crude Oil CMA 2018 — $ — $ — 1,529 $ 0.14 $ (220 ) Total Rollfactor — 1,529 $ (220 ) Commodity Derivatives Fair Value $ (254,522 ) _____________ (1) Approximately 49.2 percent of the fair value of our commodity derivative assets and 13.0 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). (2) These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month. We have not elected to designate any of our derivative instruments as cash flow hedges; 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, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 433 $ 7,340 Basis protection derivative contracts Fair value of derivatives 7,111 6,998 Rollfactor derivative contracts Fair value of derivatives 11 — 7,555 14,338 Non-current Commodity derivative contracts Fair value of derivatives 3,949 — Total derivative assets $ 11,504 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 204,145 $ 77,999 Basis protection derivative contracts Fair value of derivatives 638 234 Rollfactor derivative contracts Fair value of derivatives 230 1,069 205,013 79,302 Non-current Commodity derivative contracts Fair value of derivatives 60,744 22,343 Basis protection derivative contracts Fair value of derivatives 269 — 61,013 22,343 Total derivative liabilities $ 266,026 $ 101,645 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 2018 2017 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (48,096 ) $ 9,585 $ (90,542 ) $ 22,151 Net change in fair value of unsettled derivatives (46,298 ) (61,763 ) (167,218 ) 64,307 Total commodity price risk management gain (loss), net $ (94,394 ) $ (52,178 ) $ (257,760 ) $ 86,458 Our decrease in net settlements for the nine months ended September 30, 2018 was partially offset by an $11.3 million realized gain on the early settlement of certain commodity derivative basis protection positions, including $10.3 million for the early settlement of crude oil basis protection instruments and $1.0 million for the early settlement of natural gas basis protection instruments, both for our Delaware Basin operations. The volumes associated with these instruments were impacted by certain marketing agreements entered into during the nine months ended September 30, 2018 , which eliminated the underlying sale price variability, and therefore there was no longer a variable to hedge. 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, 2018 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,504 $ (11,451 ) $ 53 Liability derivatives: Derivative instruments, at fair value $ 266,026 $ (11,451 ) $ 254,575 As of December 31, 2017 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 14,338 $ (14,173 ) $ 165 Liability derivatives: Derivative instruments, at fair value $ 101,645 $ (14,173 ) $ 87,472 |
Properties and Equipment
Properties and Equipment | 9 Months Ended |
Sep. 30, 2018 | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment Disclosure | PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"): September 30, 2018 December 31, 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 5,204,267 $ 4,356,922 Unproved 866,719 1,097,317 Total crude oil and natural gas properties 6,070,986 5,454,239 Infrastructure, pipeline and other 141,045 109,359 Land and buildings 12,544 10,960 Construction in progress 318,949 196,024 Properties and equipment, at cost 6,543,524 5,770,582 Accumulated DD&A (2,234,503 ) (1,837,115 ) Properties and equipment, net $ 4,309,021 $ 3,933,467 The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Impairment of proved and unproved properties $ 1,488 $ 252,623 $ 194,146 $ 282,188 Amortization of individually insignificant unproved properties — 117 84 311 Impairment of crude oil and natural gas properties $ 1,488 $ 252,740 $ 194,230 $ 282,499 During the nine months ended September 30, 2018 , we recorded impairment charges totaling $194.2 million as we identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leasehold typically has a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties and is further impacted by widening crude oil and natural gas differentials and increased well development costs. We intend to focus our future Delaware Basin development in our oilier core areas where we have identified approximately 450 mid-length lateral equivalent Wolfcamp drilling locations. We continue to explore options for our non-focus areas and monitor them for possible future impairment based on similar analyses. We determined the fair value of the properties 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. Additionally, we corrected an error in our calculation of the unproved properties and goodwill impairment originally reported in the quarter ended September 30, 2017. The correction of the error resulted in an additional impairment charge of $6.3 million , recorded in the three months ended March 31, 2018, which we have included in the impairment of properties and equipment expense line in our condensed consolidated statement of operations. We evaluated the error under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the impact of the error did not have a material impact on our previously-issued financial statements or those of the period of correction. Utica Shale Divestiture. In March 2018, we completed the disposition of our Utica Shale properties (the "Utica Shale Divestiture") for net cash proceeds of approximately $39.0 million . We recorded a loss on sale of properties and equipment of $1.4 million for the nine months ended September 30, 2018 , which included post-closing adjustments. The divestiture of the Utica Shale properties did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation. Suspended Well Costs. During the three months ended September 30, 2018 , we spud one well in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the well as of September 30, 2018 as the well had not been completed as of that date. Therefore, we have classified the capitalized costs of the well as suspended well costs as of September 30, 2018 while we continue to conduct completion and testing operations to determine the existence of proved reserves. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets: Nine Months Ended September 30, 2018 Year Ended December 31, 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 29,203 51,776 Reclassifications to proved properties (43,145 ) (36,328 ) Ending balance $ 1,506 $ 15,448 Number of wells pending determination at period end 1 3 Acreage Exchange. In July 2018, we entered into an acreage exchange transaction that involved the consolidation of certain acreage positions in the core area of the Wattenberg Field. Upon closing, we received approximately 2,500 net acres and $3.7 million in cash in exchange for approximately 2,600 acres. The difference in the number of net acres was primarily due to variances in working and net revenue interests. Based upon our analysis of risk, timing and expected future cash flows, it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage costs were recorded at the previous historical cost of the assets we exchanged, less cash received. |
Other Accrued Expenses Other Ac
Other Accrued Expenses Other Accrued Expenses (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Other Accrued Expenses [Abstract] | |
Other Income and Other Expense Disclosure [Text Block] | OTHER ACCRUED EXPENSES AND OTHER LIABILITIES Other Accrued Expenses. The following table presents the components of other accrued expenses as of: September 30, 2018 December 31, 2017 (in thousands) Employee benefits $ 16,555 $ 22,383 Asset retirement obligations 16,006 15,801 Environmental expenses 3,415 1,374 Other 3,284 3,429 Other accrued expenses $ 39,260 $ 42,987 Other Liabilities. The following table presents the components of other liabilities as of: September 30, 2018 December 31, 2017 (in thousands) Production taxes $ 44,817 $ 50,476 Deferred oil gathering credit 22,613 — Other 9,557 6,857 Other liabilities $ 76,987 $ 57,333 Deferred Oil Gathering Credit. On January 31, 2018, we received a payment of $24.1 million from Saddle Butte Rockies Midstream, LLC for the execution of an amendment to an existing crude oil purchase and sale agreement signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, dedicates crude oil from the majority of our Wattenberg Field acreage to Saddle Butte's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $0.4 million and $1.1 million for the three and nine months ended September 30, 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our condensed consolidated statements of operations. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt consisted of the following as of: September 30, 2018 December 31, 2017 (in thousands) Senior notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (24,697 ) (30,328 ) Unamortized debt issuance costs (2,884 ) (3,615 ) Net of unamortized discount and debt issuance costs 172,419 166,057 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (5,835 ) (6,570 ) Net of unamortized debt issuance costs 394,165 393,430 5.75% Senior Notes due May 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (6,851 ) (7,555 ) Net of unamortized debt issuance costs 593,149 592,445 Total senior notes 1,159,733 1,151,932 Revolving credit facility due May 2023 75,000 — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,234,733 $ 1,151,932 Senior Notes 2021 Convertible Notes. In September 2016 , we issued $200 million of 1.125% convertible notes due September 15, 2021 (the "2021 Convertible Notes") in a public offering. Interest is payable in cash semiannually on each March 15 and September 15 . The conversion 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 were capitalized as debt issuance costs. As of September 30, 2018 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using the effective interest method. 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, with cash paid in lieu of fractional shares. 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 on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. 2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. In June 2018, 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 July 2018. The 2026 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually on May 15 and November 15 . The first interest payment occurred on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. Our wholly-owned subsidiary PDC Permian, Inc. guarantees our obligations under the 2021 Convertible Notes, the 2026 Senior Notes and the 2024 Senior Notes (collectively, 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, 2018 , we were in compliance with all covenants related to the Notes. Revolving Credit Facility In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”) with certain banks and other lenders, including JPMorgan Chase Bank, N.A. as administrative agent. The Restated Credit Agreement amends and restates our Third Amended and Restated Credit Agreement dated as of May 21, 2013, as amended. Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion , an initial borrowing base of $1.3 billion and an initial elected commitment amount of $700 million . The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our Notes. In addition, the Restated Credit Agreement extends the maturity date of the facility from May 2020 to May 2023 , reflects improved covenant flexibility and certain reductions in interest rates applicable to borrowings under the facility and includes a $25 million swingline facility. In October 2018, we increased the commitment level on our revolving credit facility to the current borrowing base amount of $1.3 billion . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. 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 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, 2018 , the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent . Principal payments are generally not required until the revolving credit facility expires in May 2023 , unless 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, 2018 , we were in compliance with all the revolving credit facility covenants. As of September 30, 2018 and December 31, 2017 , debt issuance costs related to our revolving credit facility were $8.6 million and $6.2 million , respectively, and are included in other assets on the condensed consolidated balance sheets. As of September 30, 2018 , the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.2 percent . |
Capital Leases (Notes)
Capital Leases (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 December 31, 2017 (in thousands) Vehicles $ 7,255 $ 6,249 Accumulated depreciation (2,931 ) (1,882 ) $ 4,324 $ 4,367 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) 2019 $ 2,165 2020 2,427 2021 583 2022 138 2023 113 5,426 Executory cost (260 ) Amount representing interest (551 ) Present value of minimum lease payments $ 4,615 Short-term capital lease obligations $ 1,897 Long-term capital lease obligations 2,718 $ 4,615 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. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
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 federal corporate statutory income tax rate decreased from 35 percent in 2017 to 21 percent in 2018 pursuant to the 2017 Tax Cuts and Jobs Act (the "2017 Tax Act"). The effective income tax rates for the three and nine months ended September 30, 2018 and 2017 are based upon a full year forecasted tax benefit on loss. The effective income tax rates differ from the statutory federal tax rate, primarily due to state taxes, stock-based compensation, nondeductible officers’ compensation, nondeductible lobbying expenses, nondeductible penalties and federal tax credits. The effective income tax rate for the nine months ended September 30, 2018 includes discrete income tax provision items of $2.6 million relating to a valuation allowance placed on state tax credits offset by a $1.5 million benefit for additional deductions and credits claimed on the filed 2017 and 2016 federal and state tax returns. The net discrete tax expense from these discrete tax adjustments during the three and nine months ended September 30, 2018 resulted in a 12.3 percent and 0.5 percent decrease to our effective income tax rates, respectively. We anticipate the potential for increased periodic volatility in future effective 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, 2018 were 53.0 percent and 23.3 percent benefit on loss, respectively, compared to 29.5 percent and 25.8 percent benefit on loss for the three and nine months ended September 30, 2017 , respectively. The most significant elements related to the decrease in the effective income tax rate for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 is the noted reduction of the 2018 federal statutory rate to 21 percent and nondeductible impairment of goodwill during the nine months ended September 30, 2017 . As of September 30, 2018 , 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 ("IRS") Compliance Assurance Program for the 2017 and 2018 tax years. We have received final acceptance of our 2016 federal income tax return from the Joint Tax Committee. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2018 | |
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, 2017 $ 87,306 Obligations incurred with development activities 2,147 Obligations incurred with acquisition 4,326 Accretion expense 3,773 Revisions in estimated cash flows 754 Obligations discharged with asset retirements and divestiture (9,593 ) Balance at September 30, 2018 88,713 Current portion (16,006 ) Long-term portion $ 72,707 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. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. 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, 2018 | |
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 2019 2020 2021 2022 2023 and Total Expiration Natural gas (MMcf) Wattenberg Field 19,142 30,850 31,025 31,025 98,717 210,759 April 30, 2026 Delaware Basin 48,387 41,426 25,075 5,326 — 120,214 December 31, 2021 Gas Marketing 7,117 7,136 7,117 6,228 — 27,598 August 31, 2022 Total 74,646 79,412 63,217 42,579 98,717 358,571 Crude oil (MBbls) Wattenberg Field 7,888 7,302 5,475 5,475 3,180 29,320 April 30, 2023 Delaware Basin 6,651 8,833 8,214 8,030 10,054 41,782 December 31, 2023 Total 14,539 16,135 13,689 13,505 13,234 71,102 Dollar commitment (in thousands) $ 92,736 $ 87,056 $ 72,476 $ 71,457 $ 138,271 $ 461,996 Wattenberg Field. In anticipation of our future drilling activities in the Wattenberg Field, we have 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 completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018. The second plant is currently scheduled to be completed in the second quarter of 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. 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 in these volume commitments may be offset by other 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 meet both the baseline and incremental volumes and we believe that the contractual target profit margin will be achieved with minimal payment from us, if any. Delaware Basin . In May 2018, we entered into two firm sales agreements that are effective from June 1, 2018 through December 31, 2023 for an initial 11,400 barrels of crude oil per day and incrementally increasing to 26,400 barrels of crude oil per day with an integrated marketing company for our crude oil production in the Delaware Basin. These agreements are expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. Commodity Sales . For the three and nine months ended September 30, 2018 , amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $11.0 million and $16.2 million , respectively, and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales in our condensed consolidated statements of operations. In addition, for both the three and nine months ended September 30, 2018 , $0.8 million related to long-term transportation volumes were recorded in transportation, gathering and processing expense in our condensed consolidated statements of operations. For the three and nine months ended September 30, 2017 , amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.6 million and $7.4 million , respectively, and were recorded in transportation, gathering and processing expense in our condensed consolidated statements of operations. In March 2018, we completed the disposition of our Utica Shale properties. Litigation and Legal Items. We are involved in various legal proceedings. We review 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 our best interests. We have 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. 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. Action Regarding Partnerships . In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP, against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to take action on their claims. On March 14, 2018, the motion was denied as moot by the court because the plaintiffs requested leave to amend their complaint. In late April 2018, the plaintiffs filed an amendment to their complaint. Such amendment primarily alleges additional facts to support the plaintiffs’ claims and purports to add direct class action claims in addition to the original derivative claims. The amendment also adds three new individual defendants, all of whom are currently independent members of our Board of Directors. We moved to dismiss the claims against the individuals named as defendants and in response, the plaintiffs filed a second amended complaint on July 10, 2018. We filed a motion to dismiss this second amended complaint and the claims against the individuals named as defendants on July 31, 2018 and are awaiting a ruling at this time. We are currently unable to estimate any potential damages resulting from this lawsuit. Partnership Bankruptcy Filings. On October 30, 2018, our two remaining affiliated partnerships (collectively, the "Partnerships") filed a petition under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") with the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). The Partnerships intend to enter into a transaction with us, pursuant to which the Partnerships will sell substantially all of their assets to us through a Chapter 11 plan of liquidation (the "Chapter 11 Plan"). The Partnerships remain in possession of their assets and continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. In addition, a third-party (the “Responsible Party”) has been designated for the Partnerships. The Responsible Party is expected to oversee all actions for the Partnerships in connection with the Chapter 11 Proceedings, including actions relating to the anticipated transactions with us and seeking approval of the Chapter 11 Plan. We do not believe that the Partnership's Chapter 11 Proceedings will have a material adverse effect on our financial position, results of operations or liquidity, but we cannot predict the outcome of such proceedings. 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, 2018 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 or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $ 130,000 , of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. Clean Air Act 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. In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit and the above referenced Compliance Advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. 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) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (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 . We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. We are in the process of implementing this program. In the third quarter of 2018, we identified certain immaterial deficiencies in our implementation of the program. We have reported these immaterial deficiencies to the appropriate authorities and have remediated them. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . |
Common Stock
Common Stock | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | COMMON STOCK Stock-Based Compensation Plans 2018 Equity Incentive Plan . In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee"), with a minimum one-year vesting period, applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. 2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may use the 2010 Plan to grant awards. However, the share reserve of the 2010 Plan is nearly depleted. As of September 30, 2018 , there were 233,783 shares available for grant under the 2010 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, 2018 2017 2018 2017 (in thousands) Stock-based compensation expense $ 5,578 $ 4,761 $ 16,357 $ 14,587 Income tax benefit (1,337 ) (1,781 ) (3,921 ) (5,457 ) Net stock-based compensation expense $ 4,241 $ 2,980 $ 12,436 $ 9,130 Stock Appreciation Rights SARs vest ratably over a three-year period and may generally 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. We had 7,962 SARs expire during the three months ended September 30, 2018 . No SARs were awarded during the nine months ended September 30, 2018 . Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of September 30, 2018 was $0.9 million . The cost is expected to be recognized over a weighted-average period of 0.9 years . Restricted Stock Units Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs 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 RSUs to all employees, including executive officers, for the nine months ended September 30, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 416,687 50.85 Vested (219,768 ) 58.26 Forfeited (36,137 ) 57.22 Non-vested at September 30, 2018 632,914 54.91 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: Nine Months Ended September 30, 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 11,178 $ 13,266 Total intrinsic value of time-based awards non-vested 30,987 25,762 Market price per share as of September 30, 2018 48.96 49.03 Weighted-average grant date fair value per share 50.85 66.00 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, 2018 was $24.5 million . This cost is expected to be recognized over a weighted-average period of 1.9 years. Performance Stock Units Market-Based Awards. The fair value of the market-based PSUs 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 awarded a total of 90,778 market-based PSUs to our executive officers during the nine months ended September 30, 2018 . In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2020, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between 0 percent and 200 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Nine Months Ended September 30, 2018 2017 Expected term of award (in years) 3 3 Risk-free interest rate 2.4 % 1.4 % Expected volatility 42.3 % 51.4 % 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, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Forfeited (4,128 ) 94.02 Non-vested at September 30, 2018 138,999 74.57 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: Nine Months Ended September 30, 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards non-vested $ 6,805 $ 3,750 Market price per common share as of September 30, 48.96 49.03 Weighted-average grant date fair value per share 69.98 94.02 Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of September 30, 2018 was $6.1 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. 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 of Directors from time to time. Through September 30, 2018 , no shares of preferred stock have been issued. |
Earnings per share
Earnings per share | 9 Months Ended |
Sep. 30, 2018 | |
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, 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 our weighted-average basic and diluted shares outstanding: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 66,073 65,865 66,032 65,825 Weighted-average common shares and equivalents outstanding - diluted 66,073 65,865 66,032 65,825 We reported a net loss for the three and nine months ended September 30, 2018 and 2017 . As a result, our basic and diluted weighted-average common shares outstanding were the same for that 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, 2018 2017 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSU and PSU 719 588 655 585 Other equity-based awards 314 48 319 82 Total anti-dilutive common share equivalents 1,033 636 974 667 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, 2018 and 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. |
Subsidiary Guarantor Subsidiary
Subsidiary Guarantor Subsidiary Guarantor (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Subsidiary Guarantor [Abstract] | |
Guarantees [Text Block] | SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior 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 senior 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 percent owned by the Parent. The senior 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, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 1,369 $ — $ — $ 1,369 Accounts receivable, net 186,274 54,881 — 241,155 Fair value of derivatives 7,555 — — 7,555 Prepaid expenses and other current assets 5,983 730 — 6,713 Total current assets 201,181 55,611 — 256,792 Properties and equipment, net 2,216,649 2,092,372 — 4,309,021 Intercompany receivable 404,641 — (404,641 ) — Investment in subsidiaries 1,504,791 — (1,504,791 ) — Fair value of derivatives 3,949 — — 3,949 Other assets 26,327 5,135 — 31,462 Total Assets $ 4,357,538 $ 2,153,118 $ (1,909,432 ) $ 4,601,224 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 135,264 $ 115,817 $ — $ 251,081 Production tax liability 53,573 5,966 — 59,539 Fair value of derivatives 205,013 — — 205,013 Funds held for distribution 86,173 18,086 — 104,259 Accrued interest payable 15,419 6 — 15,425 Other accrued expenses 38,366 894 — 39,260 Total current liabilities 533,808 140,769 — 674,577 Intercompany payable — 404,641 (404,641 ) — Long-term debt 1,234,733 — — 1,234,733 Deferred income taxes 44,066 94,897 — 138,963 Asset retirement obligations 65,248 7,459 — 72,707 Fair value of derivatives 61,013 — — 61,013 Other liabilities 76,426 561 — 76,987 Total liabilities 2,015,294 648,327 (404,641 ) 2,258,980 Commitments and contingent liabilities Stockholders' Equity Common shares 661 — — 661 Additional paid-in capital 2,514,861 1,766,775 (1,766,775 ) 2,514,861 Retained earnings (170,126 ) (261,984 ) 261,984 (170,126 ) Treasury shares (3,152 ) — — (3,152 ) Total stockholders' equity 2,342,244 1,504,791 (1,504,791 ) 2,342,244 Total Liabilities and Stockholders' Equity $ 4,357,538 $ 2,153,118 $ (1,909,432 ) $ 4,601,224 Condensed Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Commitments and contingent liabilities Stockholders' Equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Condensed Consolidating Statements of Operations Three Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 280,866 $ 91,573 $ — $ 372,439 Commodity price risk management loss, net (94,394 ) — — (94,394 ) Other income 2,300 372 — 2,672 Total revenues 188,772 91,945 — 280,717 Costs, expenses and other Lease operating expenses 23,219 9,827 — 33,046 Production taxes 17,852 6,132 — 23,984 Transportation, gathering and processing expenses 4,520 4,714 — 9,234 Exploration, geologic and geophysical expense 279 753 — 1,032 Impairment of properties and equipment 98 1,390 — 1,488 General and administrative expense 43,886 4,354 — 48,240 Depreciation, depletion and amortization 97,370 50,170 — 147,540 Accretion of asset retirement obligations 1,084 116 — 1,200 (Gain) loss on sale of properties and equipment (141 ) 2,259 — 2,118 Other expenses 2,711 — — 2,711 Total costs, expenses and other 190,878 79,715 — 270,593 Income (loss) from operations (2,106 ) 12,230 — 10,124 Interest expense (18,232 ) 610 — (17,622 ) Interest income 188 — — 188 Income (loss) before income taxes (20,150 ) 12,840 — (7,310 ) Income tax (expense) benefit 5,753 (1,877 ) — 3,876 Equity in income of subsidiary 10,963 — (10,963 ) — Net income (loss) $ (3,434 ) $ 10,963 $ (10,963 ) $ (3,434 ) Condensed Consolidating Statements of Operations Three Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 199,565 $ 33,168 $ — $ 232,733 Commodity price risk management loss, net (52,178 ) — — (52,178 ) Other income 2,628 52 — 2,680 Total revenues 150,015 33,220 — 183,235 Costs, expenses and other Lease operating expenses 18,181 7,172 — 25,353 Production taxes 13,467 2,049 — 15,516 Transportation, gathering and processing expenses 5,970 3,824 — 9,794 Exploration, geologic and geophysical expense 216 41,692 — 41,908 Impairment of properties and equipment 1,148 251,592 — 252,740 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 26,207 3,092 — 29,299 Depreciation, depletion and amortization 106,623 18,615 — 125,238 Accretion of asset retirement obligations 1,386 86 — 1,472 Gain on sale of properties and equipment (62 ) — — (62 ) Other expenses 2,947 — — 2,947 Total costs, expenses and other 176,083 403,243 — 579,326 Loss from operations (26,068 ) (370,023 ) — (396,091 ) Interest expense (19,647 ) 372 — (19,275 ) Interest income 479 — — 479 Loss before income taxes (45,236 ) (369,651 ) — (414,887 ) Income tax benefit 30,274 92,076 — 122,350 Equity in loss of subsidiary (277,575 ) — 277,575 — Net loss $ (292,537 ) $ (277,575 ) $ 277,575 $ (292,537 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 757,263 $ 246,334 $ — $ 1,003,597 Commodity price risk management loss, net (257,760 ) — — (257,760 ) Other income 7,295 716 — 8,011 Total revenues 506,798 247,050 — 753,848 Costs, expenses and other Lease operating expenses 68,013 26,929 — 94,942 Production taxes 50,122 16,635 — 66,757 Transportation, gathering and processing expenses 11,361 14,150 — 25,511 Exploration, geologic and geophysical expense 887 3,666 — 4,553 Impairment of properties and equipment 191 194,039 — 194,230 General and administrative expense 108,597 12,586 — 121,183 Depreciation, depletion and amortization 284,963 124,989 — 409,952 Accretion of asset retirement obligations 3,460 313 — 3,773 Loss on sale of properties and equipment 940 2,259 — 3,199 Other expenses 8,187 — — 8,187 Total costs, expenses and other 536,721 395,566 — 932,287 Loss from operations (29,923 ) (148,516 ) — (178,439 ) Interest expense (54,244 ) 1,683 — (52,561 ) Interest income 405 — — 405 Loss before income taxes (83,762 ) (146,833 ) — (230,595 ) Income tax benefit 19,678 34,087 — 53,765 Equity in loss of subsidiary (112,746 ) — 112,746 — Net loss $ (176,830 ) $ (112,746 ) $ 112,746 $ (176,830 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 561,132 $ 74,895 $ — $ 636,027 Commodity price risk management gain, net 86,458 — — 86,458 Other income 9,512 103 — 9,615 Total revenues 657,102 74,998 — 732,100 Costs, expenses and other Lease operating expenses 49,555 15,615 — 65,170 Production taxes 38,000 4,957 — 42,957 Transportation, gathering and processing expenses 16,953 5,231 — 22,184 Exploration, geologic and geophysical expense 744 43,151 — 43,895 Impairment of properties and equipment 2,282 280,217 — 282,499 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 76,353 8,792 — 85,145 Depreciation, depletion and amortization 317,088 43,479 — 360,567 Accretion of asset retirement obligations 4,660 246 — 4,906 Gain on sale of properties and equipment (754 ) — — (754 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Other expenses 10,365 — — 10,365 Total costs, expenses and other 475,043 476,809 — 951,852 Income (loss) from operations 182,059 (401,811 ) — (219,752 ) Interest expense (59,044 ) 685 — (58,359 ) Interest income 1,487 — — 1,487 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 ) Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 405,326 $ 172,508 $ — $ 577,834 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (360,457 ) (325,092 ) — (685,549 ) Capital expenditures for other properties and equipment (2,834 ) (905 ) — (3,739 ) Acquisition of crude oil and natural gas properties, including settlement adjustments (181,501 ) (71 ) — (181,572 ) Proceeds from sale of properties and equipment 1,918 525 — 2,443 Proceeds from divestiture 43,493 — — 43,493 Restricted cash 1,249 — — 1,249 Intercompany transfers (153,121 ) — 153,121 — Net cash from investing activities (651,253 ) (325,543 ) 153,121 (823,675 ) Cash flows from financing activities: Proceeds from revolving credit facility 629,000 — — 629,000 Repayment of revolving credit facility (554,000 ) — — (554,000 ) Payment of debt issuance costs (4,086 ) — — (4,086 ) Purchases of treasury shares (4,700 ) — — (4,700 ) Other (842 ) (86 ) — (928 ) Intercompany transfers — 153,121 (153,121 ) — Net cash from financing activities 65,372 153,035 (153,121 ) 65,286 Net change in cash, cash equivalents and restricted cash (180,555 ) — — (180,555 ) Cash, cash equivalents and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents and restricted cash, end of period $ 9,370 $ — $ — $ 9,370 Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 391,965 $ 28,687 $ — $ 420,652 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas 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 (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 ) Sale of short-term investments 49,890 — — 49,890 Purchase 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: Purchases of treasury shares (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, cash equivalents and restricted cash (107,197 ) 8,776 — (98,421 ) Cash, cash equivalents and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents and restricted cash, end of period $ 133,290 $ 12,389 $ — $ 145,679 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | In May 2014, the Financial Accounting Standards Board ("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 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. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, 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 the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. 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 the 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. Adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at September 30, 2018 and 2017 and December 31, 2017 , which sum to the total of cash, cash equivalents and restricted cash in the condensed consolidated statements of cash flows: September 30, 2018 December 31, 2017 September 30, 2017 (in thousands) Cash and cash equivalents $ 1,369 $ 180,675 $ 136,429 Restricted cash 8,001 9,250 9,250 Cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows $ 9,370 $ 189,925 $ 145,679 Restricted cash is included in other assets on the condensed consolidated balance sheets at September 30, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. 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 effective July 1, 2018. Adoption of this standard did not have an impact on our condensed consolidated financial statements or related disclosures. On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $2.9 million and $8.2 million in the three and nine months ended September 30, 2017 , respectively, with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for the three and nine months ended September 30, 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three and nine months ended September 30, 2018 and 2017 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
Consolidation, Policy | The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries and our proportionate share of our 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, 2017 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 2017 Form 10-K. Our results of operations and cash flows for the nine months ended September 30, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period |
Recently Issued Accounting Policy [Policy Text Block] | In February 2016, the FASB issued an accounting update and subsequent amendments 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. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are continuing to assess the full effect the guidance will have on our existing accounting policies and our condensed consolidated financial statements, and we expect there will be an increase in assets and liabilities on our condensed consolidated balance sheets at adoption due to the recording of right-of-use assets and corresponding lease liabilities. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2018, the FASB issued an accounting update for fair value disclosures that removes or modifies current disclosures and adds additional disclosures. The update to the guidance is the result of the FASB's test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. The guidance for the additional disclosures is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have 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, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. |
Asset Retirement Obligations As
Asset Retirement Obligations Asset Retirement Obligations (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation [Policy Text Block] | 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. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets. |
Summary of Significant Accounti
Summary of Significant Accounting Policies Cash, Cash Equivalents, and Restricted Cash (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Cash and Cash Equivalents [Line Items] | |
Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at September 30, 2018 and 2017 and December 31, 2017 , which sum to the total of cash, cash equivalents and restricted cash in the condensed consolidated statements of cash flows: September 30, 2018 December 31, 2017 September 30, 2017 (in thousands) Cash and cash equivalents $ 1,369 $ 180,675 $ 136,429 Restricted cash 8,001 9,250 9,250 Cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows $ 9,370 $ 189,925 $ 145,679 |
Business Combination Business_2
Business Combination Business Combinations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Business Combination, Segment Allocation [Table Text Block] | The details of the final purchase price and allocation of the purchase price for the transaction, are presented below (in thousands): September 30, 2018 Acquisition costs: Cash $ 168,560 Deposit made in prior period 21,000 Total cash consideration 189,560 Other purchase price adjustments 10,422 Total acquisition costs $ 199,982 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 468 Crude oil and natural gas properties - proved 205,834 Other assets 2,796 Total assets acquired 209,098 Liabilities assumed: Current liabilities (4,429 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,116 ) Total identifiable net assets acquired $ 199,982 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Capitalized Contract Cost [Table Text Block] | The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the nine months ended September 30, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,217 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,024 ) Ending balance, September 30, 2018 $ 2,939 |
Disaggregation of Revenue [Table Text Block] | Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the three and nine months ended September 30, 2018 and 2017 (in thousands): Three Months Ended September 30, Nine Months Ended September 30, Revenue by Commodity and Operating Region 2018 2017 (1) Percentage Change 2018 2017 (1) Percentage Change Crude oil Wattenberg Field $ 216,346 $ 134,785 60.5 % $ 576,645 $ 369,231 56.2 % Delaware Basin 68,341 19,654 247.7 % 184,357 49,519 272.3 % Utica Shale (2) — 2,581 (100.0 )% 2,696 10,067 (73.2 )% Total $ 284,687 $ 157,020 81.3 % $ 763,698 $ 428,817 78.1 % Natural gas Wattenberg Field $ 27,762 $ 32,919 (15.7 )% $ 80,174 $ 99,537 (19.5 )% Delaware Basin 6,994 7,627 (8.3 )% 22,145 12,863 72.2 % Utica Shale (2) — 910 (100.0 )% 1,109 4,330 (74.4 )% Total $ 34,756 $ 41,456 (16.2 )% $ 103,428 $ 116,730 (11.4 )% NGLs Wattenberg Field $ 36,758 $ 27,352 34.4 % $ 95,799 $ 74,594 28.4 % Delaware Basin 16,238 5,887 175.8 % 39,832 12,513 218.3 % Utica Shale (2) — 1,018 (100.0 )% 840 3,373 (75.1 )% Total $ 52,996 $ 34,257 54.7 % $ 136,471 $ 90,480 50.8 % Revenue by Operating Region Wattenberg Field $ 280,866 $ 195,056 44.0 % $ 752,618 $ 543,362 38.5 % Delaware Basin 91,573 33,168 176.1 % 246,334 74,895 228.9 % Utica Shale (2) — 4,509 (100.0 )% 4,645 17,770 (73.9 )% Total $ 372,439 $ 232,733 60.0 % $ 1,003,597 $ 636,027 57.8 % ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for the three and nine months ended September 30, 2017 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. |
Fair Value Measurements and D_2
Fair Value Measurements and Disclosures (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 of the hierarchy. Our collars and propane fixed-price swaps are included in Level 3 of the hierarchy. Our basis swaps are included in Level 2 and Level 3 of the hierarchy. 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, 2018 December 31, 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 5,843 $ 5,661 $ 11,504 $ 12,949 $ 1,389 $ 14,338 Total liabilities (231,503 ) (34,523 ) (266,026 ) (90,569 ) (11,076 ) (101,645 ) Net liability $ (225,660 ) $ (28,862 ) $ (254,522 ) $ (77,620 ) $ (9,687 ) $ (87,307 ) |
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, 2018 2017 2018 2017 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (19,100 ) $ 8,619 $ (9,687 ) $ (9,574 ) Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (16,175 ) (14,075 ) (23,029 ) 8,547 Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net 6,413 (1,013 ) 3,854 (5,442 ) Fair value of Level 3 instruments, net liability end of period $ (28,862 ) $ (6,469 ) $ (28,862 ) $ (6,469 ) 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 $ (7,451 ) $ (8,711 ) $ (4,229 ) $ (583 ) |
Fair Value Measurements and D_3
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, 2018 | |
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: As of September 30, 2018 As of December 31, 2017 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) (in millions) Senior notes: 2021 Convertible Notes $ 194.2 97.1 % $ 195.6 97.8 % 2024 Senior Notes 393.8 98.5 % 416.0 104.0 % 2026 Senior Notes 570.8 95.1 % 616.5 102.8 % |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 9 Months Ended | |
Sep. 30, 2018 | ||
Derivative [Line Items] | ||
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | As of September 30, 2018 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu Propane - MBbls) Weighted- Average Contract Price Fair Value September 30, 2018 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2018 528 $ 45.59 $ 56.82 2,968 $ 52.23 $ (69,943 ) 2019 2,600 56.54 68.13 8,400 53.86 (157,085 ) 2020 3,600 55.00 71.68 5,000 62.07 (30,034 ) Total Crude Oil 6,728 16,368 $ (257,062 ) Natural Gas NYMEX 2018 120 $ 3.00 $ 3.90 14,145 $ 2.93 $ (1,504 ) 2019 — — — 8,004 2.78 (15 ) Dominion South 2018 — — — 94 2.12 6 2019 — — — 121 2.13 7 Columbia 2018 — — — 3 2.40 $ — 2019 — — — 3 2.40 — Total Natural Gas 120 22,370 $ (1,506 ) Basis Protection - Crude Oil Midland Cushing 2018 — $ — $ — 182 $ (0.10 ) $ 1,713 Total Basis Protection - Crude Oil — 182 $ 1,713 Basis Protection - Natural Gas CIG 2018 — $ — $ — 9,806 $ (0.42 ) $ 3,537 2019 — — — 7,924 (0.88 ) (908 ) Waha 2018 — — — 1,713 (0.50 ) 1,862 Total Basis Protection - Natural Gas — 19,443 $ 4,491 Propane Mont Belvieu 2018 — $ — $ — 167 $ 33.97 $ (1,938 ) Total Propane — 167 $ (1,938 ) Rollfactor (2) Crude Oil CMA 2018 — $ — $ — 1,529 $ 0.14 $ (220 ) Total Rollfactor — 1,529 $ (220 ) Commodity Derivatives Fair Value $ (254,522 ) _____________ (1) Approximately 49.2 percent of the fair value of our commodity derivative assets and 13.0 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). (2) These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month. | [1],[2] |
Schedule of Derivatives 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, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 433 $ 7,340 Basis protection derivative contracts Fair value of derivatives 7,111 6,998 Rollfactor derivative contracts Fair value of derivatives 11 — 7,555 14,338 Non-current Commodity derivative contracts Fair value of derivatives 3,949 — Total derivative assets $ 11,504 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 204,145 $ 77,999 Basis protection derivative contracts Fair value of derivatives 638 234 Rollfactor derivative contracts Fair value of derivatives 230 1,069 205,013 79,302 Non-current Commodity derivative contracts Fair value of derivatives 60,744 22,343 Basis protection derivative contracts Fair value of derivatives 269 — 61,013 22,343 Total derivative liabilities $ 266,026 $ 101,645 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 2018 2017 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (48,096 ) $ 9,585 $ (90,542 ) $ 22,151 Net change in fair value of unsettled derivatives (46,298 ) (61,763 ) (167,218 ) 64,307 Total commodity price risk management gain (loss), net $ (94,394 ) $ (52,178 ) $ (257,760 ) $ 86,458 | |
Derivatives Not Designated as Hedging Instruments [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, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 433 $ 7,340 Basis protection derivative contracts Fair value of derivatives 7,111 6,998 Rollfactor derivative contracts Fair value of derivatives 11 — 7,555 14,338 Non-current Commodity derivative contracts Fair value of derivatives 3,949 — Total derivative assets $ 11,504 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 204,145 $ 77,999 Basis protection derivative contracts Fair value of derivatives 638 234 Rollfactor derivative contracts Fair value of derivatives 230 1,069 205,013 79,302 Non-current Commodity derivative contracts Fair value of derivatives 60,744 22,343 Basis protection derivative contracts Fair value of derivatives 269 — 61,013 22,343 Total derivative liabilities $ 266,026 $ 101,645 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 2018 2017 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (48,096 ) $ 9,585 $ (90,542 ) $ 22,151 Net change in fair value of unsettled derivatives (46,298 ) (61,763 ) (167,218 ) 64,307 Total commodity price risk management gain (loss), net $ (94,394 ) $ (52,178 ) $ (257,760 ) $ 86,458 Our decrease in net settlements for the nine months ended September 30, 2018 was partially offset by an $11.3 million realized gain on the early settlement of certain commodity derivative basis protection positions, including $10.3 million for the early settlement of crude oil basis protection instruments and $1.0 million for the early settlement of natural gas basis protection instruments, both for our Delaware Basin operations. The volumes associated with these instruments were impacted by certain marketing agreements entered into during the nine months ended September 30, 2018 , which eliminated the underlying sale price variability, and therefore there was no longer a variable to hedge. 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, 2018 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,504 $ (11,451 ) $ 53 Liability derivatives: Derivative instruments, at fair value $ 266,026 $ (11,451 ) $ 254,575 As of December 31, 2017 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 14,338 $ (14,173 ) $ 165 Liability derivatives: Derivative instruments, at fair value $ 101,645 $ (14,173 ) $ 87,472 | |
[1] | Approximately 49.2 percent of the fair value of our commodity derivative assets and 13.0 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). | |
[2] | These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month. |
Properties and Equipment (Table
Properties and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Oil and Gas Property [Abstract] | |
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, 2018 December 31, 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 5,204,267 $ 4,356,922 Unproved 866,719 1,097,317 Total crude oil and natural gas properties 6,070,986 5,454,239 Infrastructure, pipeline and other 141,045 109,359 Land and buildings 12,544 10,960 Construction in progress 318,949 196,024 Properties and equipment, at cost 6,543,524 5,770,582 Accumulated DD&A (2,234,503 ) (1,837,115 ) Properties and equipment, net $ 4,309,021 $ 3,933,467 |
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, 2018 2017 2018 2017 (in thousands) Impairment of proved and unproved properties $ 1,488 $ 252,623 $ 194,146 $ 282,188 Amortization of individually insignificant unproved properties — 117 84 311 Impairment of crude oil and natural gas properties $ 1,488 $ 252,740 $ 194,230 $ 282,499 |
Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block] | The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets: Nine Months Ended September 30, 2018 Year Ended December 31, 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 29,203 51,776 Reclassifications to proved properties (43,145 ) (36,328 ) Ending balance $ 1,506 $ 15,448 Number of wells pending determination at period end 1 3 |
Other Accrued Expenses Other _2
Other Accrued Expenses Other Accrued Expenses (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Other Accrued Expense, Current [Abstract] | |
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block] | The following table presents the components of other accrued expenses as of: September 30, 2018 December 31, 2017 (in thousands) Employee benefits $ 16,555 $ 22,383 Asset retirement obligations 16,006 15,801 Environmental expenses 3,415 1,374 Other 3,284 3,429 Other accrued expenses $ 39,260 $ 42,987 |
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Noncurrent [Text Block] | The following table presents the components of other liabilities as of: September 30, 2018 December 31, 2017 (in thousands) Production taxes $ 44,817 $ 50,476 Deferred oil gathering credit 22,613 — Other 9,557 6,857 Other liabilities $ 76,987 $ 57,333 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt consisted of the following as of: September 30, 2018 December 31, 2017 (in thousands) Senior notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (24,697 ) (30,328 ) Unamortized debt issuance costs (2,884 ) (3,615 ) Net of unamortized discount and debt issuance costs 172,419 166,057 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (5,835 ) (6,570 ) Net of unamortized debt issuance costs 394,165 393,430 5.75% Senior Notes due May 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (6,851 ) (7,555 ) Net of unamortized debt issuance costs 593,149 592,445 Total senior notes 1,159,733 1,151,932 Revolving credit facility due May 2023 75,000 — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,234,733 $ 1,151,932 |
Capital Leases (Tables)
Capital Leases (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Capital Leases [Abstract] | |
Schedule of Capital Leased Assets [Table Text Block] | The following table presents vehicles under capital lease as of: September 30, 2018 December 31, 2017 (in thousands) Vehicles $ 7,255 $ 6,249 Accumulated depreciation (2,931 ) (1,882 ) $ 4,324 $ 4,367 |
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) 2019 $ 2,165 2020 2,427 2021 583 2022 138 2023 113 5,426 Executory cost (260 ) Amount representing interest (551 ) Present value of minimum lease payments $ 4,615 Short-term capital lease obligations $ 1,897 Long-term capital lease obligations 2,718 $ 4,615 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2017 $ 87,306 Obligations incurred with development activities 2,147 Obligations incurred with acquisition 4,326 Accretion expense 3,773 Revisions in estimated cash flows 754 Obligations discharged with asset retirements and divestiture (9,593 ) Balance at September 30, 2018 88,713 Current portion (16,006 ) Long-term portion $ 72,707 |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contigencies (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Supply Commitment | : For the Twelve Months Ending September 30, Area 2019 2020 2021 2022 2023 and Total Expiration Natural gas (MMcf) Wattenberg Field 19,142 30,850 31,025 31,025 98,717 210,759 April 30, 2026 Delaware Basin 48,387 41,426 25,075 5,326 — 120,214 December 31, 2021 Gas Marketing 7,117 7,136 7,117 6,228 — 27,598 August 31, 2022 Total 74,646 79,412 63,217 42,579 98,717 358,571 Crude oil (MBbls) Wattenberg Field 7,888 7,302 5,475 5,475 3,180 29,320 April 30, 2023 Delaware Basin 6,651 8,833 8,214 8,030 10,054 41,782 December 31, 2023 Total 14,539 16,135 13,689 13,505 13,234 71,102 Dollar commitment (in thousands) $ 92,736 $ 87,056 $ 72,476 $ 71,457 $ 138,271 $ 461,996 |
Common Stock (Tables)
Common Stock (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 2017 2018 2017 (in thousands) Stock-based compensation expense $ 5,578 $ 4,761 $ 16,357 $ 14,587 Income tax benefit (1,337 ) (1,781 ) (3,921 ) (5,457 ) Net stock-based compensation expense $ 4,241 $ 2,980 $ 12,436 $ 9,130 |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for the nine months ended September 30, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 416,687 50.85 Vested (219,768 ) 58.26 Forfeited (36,137 ) 57.22 Non-vested at September 30, 2018 632,914 54.91 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: Nine Months Ended September 30, 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 11,178 $ 13,266 Total intrinsic value of time-based awards non-vested 30,987 25,762 Market price per share as of September 30, 2018 48.96 49.03 Weighted-average grant date fair value per share 50.85 66.00 |
Restricted Stock Awards, Market-Based, Valuation assumptions | he Compensation Committee awarded a total of 90,778 market-based PSUs to our executive officers during the nine months ended September 30, 2018 . In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2020, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between 0 percent and 200 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Nine Months Ended September 30, 2018 2017 Expected term of award (in years) 3 3 Risk-free interest rate 2.4 % 1.4 % Expected volatility 42.3 % 51.4 % |
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, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Forfeited (4,128 ) 94.02 Non-vested at September 30, 2018 138,999 74.57 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: Nine Months Ended September 30, 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards non-vested $ 6,805 $ 3,750 Market price per common share as of September 30, 48.96 49.03 Weighted-average grant date fair value per share 69.98 94.02 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation | The following table presents our weighted-average basic and diluted shares outstanding: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 66,073 65,865 66,032 65,825 Weighted-average common shares and equivalents outstanding - diluted 66,073 65,865 66,032 65,825 |
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, 2018 2017 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSU and PSU 719 588 655 585 Other equity-based awards 314 48 319 82 Total anti-dilutive common share equivalents 1,033 636 974 667 |
Subsidiary Guarantor Subsidia_2
Subsidiary Guarantor Subsidiary Guarantor (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 1,369 $ — $ — $ 1,369 Accounts receivable, net 186,274 54,881 — 241,155 Fair value of derivatives 7,555 — — 7,555 Prepaid expenses and other current assets 5,983 730 — 6,713 Total current assets 201,181 55,611 — 256,792 Properties and equipment, net 2,216,649 2,092,372 — 4,309,021 Intercompany receivable 404,641 — (404,641 ) — Investment in subsidiaries 1,504,791 — (1,504,791 ) — Fair value of derivatives 3,949 — — 3,949 Other assets 26,327 5,135 — 31,462 Total Assets $ 4,357,538 $ 2,153,118 $ (1,909,432 ) $ 4,601,224 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 135,264 $ 115,817 $ — $ 251,081 Production tax liability 53,573 5,966 — 59,539 Fair value of derivatives 205,013 — — 205,013 Funds held for distribution 86,173 18,086 — 104,259 Accrued interest payable 15,419 6 — 15,425 Other accrued expenses 38,366 894 — 39,260 Total current liabilities 533,808 140,769 — 674,577 Intercompany payable — 404,641 (404,641 ) — Long-term debt 1,234,733 — — 1,234,733 Deferred income taxes 44,066 94,897 — 138,963 Asset retirement obligations 65,248 7,459 — 72,707 Fair value of derivatives 61,013 — — 61,013 Other liabilities 76,426 561 — 76,987 Total liabilities 2,015,294 648,327 (404,641 ) 2,258,980 Commitments and contingent liabilities Stockholders' Equity Common shares 661 — — 661 Additional paid-in capital 2,514,861 1,766,775 (1,766,775 ) 2,514,861 Retained earnings (170,126 ) (261,984 ) 261,984 (170,126 ) Treasury shares (3,152 ) — — (3,152 ) Total stockholders' equity 2,342,244 1,504,791 (1,504,791 ) 2,342,244 Total Liabilities and Stockholders' Equity $ 4,357,538 $ 2,153,118 $ (1,909,432 ) $ 4,601,224 Condensed Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Commitments and contingent liabilities Stockholders' Equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Condensed Consolidating Statements of Operations Three Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 280,866 $ 91,573 $ — $ 372,439 Commodity price risk management loss, net (94,394 ) — — (94,394 ) Other income 2,300 372 — 2,672 Total revenues 188,772 91,945 — 280,717 Costs, expenses and other Lease operating expenses 23,219 9,827 — 33,046 Production taxes 17,852 6,132 — 23,984 Transportation, gathering and processing expenses 4,520 4,714 — 9,234 Exploration, geologic and geophysical expense 279 753 — 1,032 Impairment of properties and equipment 98 1,390 — 1,488 General and administrative expense 43,886 4,354 — 48,240 Depreciation, depletion and amortization 97,370 50,170 — 147,540 Accretion of asset retirement obligations 1,084 116 — 1,200 (Gain) loss on sale of properties and equipment (141 ) 2,259 — 2,118 Other expenses 2,711 — — 2,711 Total costs, expenses and other 190,878 79,715 — 270,593 Income (loss) from operations (2,106 ) 12,230 — 10,124 Interest expense (18,232 ) 610 — (17,622 ) Interest income 188 — — 188 Income (loss) before income taxes (20,150 ) 12,840 — (7,310 ) Income tax (expense) benefit 5,753 (1,877 ) — 3,876 Equity in income of subsidiary 10,963 — (10,963 ) — Net income (loss) $ (3,434 ) $ 10,963 $ (10,963 ) $ (3,434 ) Condensed Consolidating Statements of Operations Three Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 199,565 $ 33,168 $ — $ 232,733 Commodity price risk management loss, net (52,178 ) — — (52,178 ) Other income 2,628 52 — 2,680 Total revenues 150,015 33,220 — 183,235 Costs, expenses and other Lease operating expenses 18,181 7,172 — 25,353 Production taxes 13,467 2,049 — 15,516 Transportation, gathering and processing expenses 5,970 3,824 — 9,794 Exploration, geologic and geophysical expense 216 41,692 — 41,908 Impairment of properties and equipment 1,148 251,592 — 252,740 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 26,207 3,092 — 29,299 Depreciation, depletion and amortization 106,623 18,615 — 125,238 Accretion of asset retirement obligations 1,386 86 — 1,472 Gain on sale of properties and equipment (62 ) — — (62 ) Other expenses 2,947 — — 2,947 Total costs, expenses and other 176,083 403,243 — 579,326 Loss from operations (26,068 ) (370,023 ) — (396,091 ) Interest expense (19,647 ) 372 — (19,275 ) Interest income 479 — — 479 Loss before income taxes (45,236 ) (369,651 ) — (414,887 ) Income tax benefit 30,274 92,076 — 122,350 Equity in loss of subsidiary (277,575 ) — 277,575 — Net loss $ (292,537 ) $ (277,575 ) $ 277,575 $ (292,537 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 757,263 $ 246,334 $ — $ 1,003,597 Commodity price risk management loss, net (257,760 ) — — (257,760 ) Other income 7,295 716 — 8,011 Total revenues 506,798 247,050 — 753,848 Costs, expenses and other Lease operating expenses 68,013 26,929 — 94,942 Production taxes 50,122 16,635 — 66,757 Transportation, gathering and processing expenses 11,361 14,150 — 25,511 Exploration, geologic and geophysical expense 887 3,666 — 4,553 Impairment of properties and equipment 191 194,039 — 194,230 General and administrative expense 108,597 12,586 — 121,183 Depreciation, depletion and amortization 284,963 124,989 — 409,952 Accretion of asset retirement obligations 3,460 313 — 3,773 Loss on sale of properties and equipment 940 2,259 — 3,199 Other expenses 8,187 — — 8,187 Total costs, expenses and other 536,721 395,566 — 932,287 Loss from operations (29,923 ) (148,516 ) — (178,439 ) Interest expense (54,244 ) 1,683 — (52,561 ) Interest income 405 — — 405 Loss before income taxes (83,762 ) (146,833 ) — (230,595 ) Income tax benefit 19,678 34,087 — 53,765 Equity in loss of subsidiary (112,746 ) — 112,746 — Net loss $ (176,830 ) $ (112,746 ) $ 112,746 $ (176,830 ) Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 561,132 $ 74,895 $ — $ 636,027 Commodity price risk management gain, net 86,458 — — 86,458 Other income 9,512 103 — 9,615 Total revenues 657,102 74,998 — 732,100 Costs, expenses and other Lease operating expenses 49,555 15,615 — 65,170 Production taxes 38,000 4,957 — 42,957 Transportation, gathering and processing expenses 16,953 5,231 — 22,184 Exploration, geologic and geophysical expense 744 43,151 — 43,895 Impairment of properties and equipment 2,282 280,217 — 282,499 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 76,353 8,792 — 85,145 Depreciation, depletion and amortization 317,088 43,479 — 360,567 Accretion of asset retirement obligations 4,660 246 — 4,906 Gain on sale of properties and equipment (754 ) — — (754 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Other expenses 10,365 — — 10,365 Total costs, expenses and other 475,043 476,809 — 951,852 Income (loss) from operations 182,059 (401,811 ) — (219,752 ) Interest expense (59,044 ) 685 — (58,359 ) Interest income 1,487 — — 1,487 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 ) Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 405,326 $ 172,508 $ — $ 577,834 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (360,457 ) (325,092 ) — (685,549 ) Capital expenditures for other properties and equipment (2,834 ) (905 ) — (3,739 ) Acquisition of crude oil and natural gas properties, including settlement adjustments (181,501 ) (71 ) — (181,572 ) Proceeds from sale of properties and equipment 1,918 525 — 2,443 Proceeds from divestiture 43,493 — — 43,493 Restricted cash 1,249 — — 1,249 Intercompany transfers (153,121 ) — 153,121 — Net cash from investing activities (651,253 ) (325,543 ) 153,121 (823,675 ) Cash flows from financing activities: Proceeds from revolving credit facility 629,000 — — 629,000 Repayment of revolving credit facility (554,000 ) — — (554,000 ) Payment of debt issuance costs (4,086 ) — — (4,086 ) Purchases of treasury shares (4,700 ) — — (4,700 ) Other (842 ) (86 ) — (928 ) Intercompany transfers — 153,121 (153,121 ) — Net cash from financing activities 65,372 153,035 (153,121 ) 65,286 Net change in cash, cash equivalents and restricted cash (180,555 ) — — (180,555 ) Cash, cash equivalents and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents and restricted cash, end of period $ 9,370 $ — $ — $ 9,370 Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 391,965 $ 28,687 $ — $ 420,652 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas 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 (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 ) Sale of short-term investments 49,890 — — 49,890 Purchase 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: Purchases of treasury shares (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, cash equivalents and restricted cash (107,197 ) 8,776 — (98,421 ) Cash, cash equivalents and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents and restricted cash, end of period $ 133,290 $ 12,389 $ — $ 145,679 |
Nature of Operations and Basi_2
Nature of Operations and Basis of Presentation Additional Information (Details) | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Oil and gas producing wells, gross | 3,000 |
Number of Operating Segments | 2 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies Reconciliation of cash, cash equivalents, and restricted cash (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |||
Cash and cash equivalents | $ 1,369 | $ 180,675 | $ 136,429 |
Restricted Cash | 8,001 | 9,250 | 9,250 |
Restricted Cash and Cash Equivalents | $ 9,370 | $ 189,925 | $ 145,679 |
Business Combination Business_3
Business Combination Business Combination (Details) $ / shares in Units, a in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018USD ($)aWells$ / shares | Sep. 30, 2018USD ($)aWells$ / shares | |
Business Acquisition [Line Items] | ||
Escrow Deposit Disbursements Related to Property Acquisition | $ 21,000 | |
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | $ (4,326) | $ (4,326) |
Oil and gas producing wells, gross | 3,000 | 3,000 |
Bayswater Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Business Acquisition, Pro Forma Revenue | $ 19,800 | $ 41,600 |
Payments to Acquire Business Two, Net of Cash Acquired | 168,560 | |
Payments to Acquire Businesses, Gross | 189,560 | |
Purchase Accounting Adjustments | 10,422 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | 468 | 468 |
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties | 205,834 | 205,834 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 2,796 | 2,796 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 209,098 | 209,098 |
Business Combination, Contingent Consideration, Liability, Current | (4,429) | (4,429) |
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | (4,687) | (4,687) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities | (9,116) | (9,116) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 199,982 | $ 199,982 |
Acquired Acreage | a | 7,400 | 7,400 |
Oil and gas drilling locations, gross | Wells | 220 | 220 |
Productive Oil Wells, Number of Wells, Net | Wells | 24 | 24 |
Business Acquisition, Pro Forma Net Income (Loss) | $ 11,600 | $ 23,600 |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares | $ 0.18 | $ 0.36 |
Revenue Recognition Contract As
Revenue Recognition Contract Assets (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Revenue from Contract with Customer [Abstract] | ||
Capitalized Contract Cost, Gross | $ 2,217 | $ 3,746 |
Capitalized Contract Cost, Amortization | (3,024) | |
Capitalized Contract Cost, Net | $ 2,939 |
Revenue Recognition Accounts Re
Revenue Recognition Accounts Receivable (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Revenue from Contract with Customer [Abstract] | ||
Accounts Receivable, Gross | $ 199.5 | $ 154.3 |
Revenue Recognition Revenue by
Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenue from Contract with Customer, Excluding Assessed Tax | $ 372,439 | $ 232,733 | $ 1,003,597 | $ 636,027 |
Revenue year over year percentage change [Line Items] | 60.00% | 57.80% | ||
Utica Shale [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | 4,509 | $ 4,645 | 17,770 |
Revenue year over year percentage change [Line Items] | (100.00%) | (73.90%) | ||
Delaware Basin [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 91,573 | 33,168 | $ 246,334 | 74,895 |
Revenue year over year percentage change [Line Items] | 176.10% | 228.90% | ||
Wattenberg Field | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 280,866 | 195,056 | $ 752,618 | 543,362 |
Revenue year over year percentage change [Line Items] | 44.00% | 38.50% | ||
NGL [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 52,996 | 34,257 | $ 136,471 | 90,480 |
Revenue year over year percentage change [Line Items] | 54.70% | 50.80% | ||
NGL [Member] | Wattenberg Field | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 36,758 | 27,352 | $ 95,799 | 74,594 |
Revenue year over year percentage change [Line Items] | 34.40% | 28.40% | ||
NGL [Member] | Delaware Basin [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 16,238 | 5,887 | $ 39,832 | 12,513 |
Revenue year over year percentage change [Line Items] | 175.80% | 218.30% | ||
NGL [Member] | Utica Shale [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | 1,018 | $ 840 | 3,373 |
Revenue year over year percentage change [Line Items] | (100.00%) | (75.10%) | ||
Natural Gas [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 34,756 | 41,456 | $ 103,428 | 116,730 |
Revenue year over year percentage change [Line Items] | (16.20%) | (11.40%) | ||
Natural Gas [Member] | Wattenberg Field | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 27,762 | 32,919 | $ 80,174 | 99,537 |
Revenue year over year percentage change [Line Items] | (15.70%) | (19.50%) | ||
Natural Gas [Member] | Delaware Basin [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 6,994 | 7,627 | $ 22,145 | 12,863 |
Revenue year over year percentage change [Line Items] | (8.30%) | 72.20% | ||
Natural Gas [Member] | Utica Shale [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | 910 | $ 1,109 | 4,330 |
Revenue year over year percentage change [Line Items] | (100.00%) | (74.40%) | ||
Crude Oil [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 284,687 | 157,020 | $ 763,698 | 428,817 |
Revenue year over year percentage change [Line Items] | 81.30% | 78.10% | ||
Crude Oil [Member] | Wattenberg Field | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 216,346 | 134,785 | $ 576,645 | 369,231 |
Revenue year over year percentage change [Line Items] | 60.50% | 56.20% | ||
Crude Oil [Member] | Delaware Basin [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 68,341 | 19,654 | $ 184,357 | 49,519 |
Revenue year over year percentage change [Line Items] | 247.70% | 272.30% | ||
Crude Oil [Member] | Utica Shale [Member] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | $ 2,581 | $ 2,696 | $ 10,067 |
Revenue year over year percentage change [Line Items] | (100.00%) | (73.20%) |
Revenue Recognition Revenue, In
Revenue Recognition Revenue, Initial Application Period Cumulative Effect Transition (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2017 | Sep. 30, 2017 | |
Revenue from Contract with Customer [Abstract] | ||
Revenue, Initial Application Period Cumulative Effect Transition, Explanation of Change | $ 2.9 | $ 8.2 |
Fair Value Measurements and D_4
Fair Value Measurements and Disclosures (Details) - Fair Value - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Assets and Liabilities at Fair Value | ||
Total assets | $ 11,504 | $ 14,338 |
Total liabilities | (266,026) | (101,645) |
Net asset (fair value) | (254,522) | (87,307) |
Significant Other Observable Inputs (Level 2) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 5,843 | 12,949 |
Total liabilities | (231,503) | (90,569) |
Net asset (fair value) | (225,660) | (77,620) |
Significant Unobservable Inputs (Level 3) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 5,661 | 1,389 |
Total liabilities | (34,523) | (11,076) |
Net asset (fair value) | $ (28,862) | $ (9,687) |
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, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Roll-forward of Level 3 Assets | ||||
Fair Value, net assets, beginning of period | $ (19,100) | $ 8,619 | $ (9,687) | $ (9,574) |
Fair Value, net assets, end of period | (28,862) | (6,469) | (28,862) | (6,469) |
Commodity Price Risk Management (loss), net | ||||
Roll-forward of Level 3 Assets | ||||
Changes in fair value included in statement of operations line item: | (16,175) | (14,075) | (23,029) | 8,547 |
Settlements included in statement of operations line items: | 6,413 | (1,013) | 3,854 | (5,442) |
Net change in fair value of unsettled derivatives included in statement of operations line item | $ (7,451) | $ (8,711) | $ (4,229) | $ (583) |
Fair Value Measurements and D_5
Fair Value Measurements and Disclosures Notes Receivable (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2018 | Sep. 30, 2017 | Mar. 31, 2016 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Oct. 14, 2014 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||||
Notes, Loans and Financing Receivable, Gross, Noncurrent | $ 39,000 | ||||||
Provision for uncollectible note receivable | $ 0 | $ 0 | $ 44,000 | $ 0 | $ (40,203) | ||
1.125% Convertible Senior Notes due 2021 [Member] | |||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||||
Notes Payable, Fair Value Disclosure | $ 194,200 | $ 194,200 | $ 195,600 | ||||
Senior Notes fair value | 97.10% | 97.10% | 97.80% | ||||
5.75% Senior Notes due 2026 [Member] | |||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||||
Notes Payable, Fair Value Disclosure | $ 570,800 | $ 570,800 | $ 616,500 | ||||
Senior Notes fair value | 95.10% | 95.10% | 102.80% | ||||
6.125% Senior Notes due 2024 [Member] | |||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||||
Notes Payable, Fair Value Disclosure | $ 393,800 | $ 393,800 | $ 416,000 | ||||
Senior Notes fair value | 98.50% | 98.50% | 104.00% |
Fair Value of Derivative and Ba
Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value | ||
Derivative Asset, Fair Value, Gross Asset | $ 11,504 | $ 14,338 |
Derivative Liability, Fair Value, Gross Liability | 266,026 | 101,645 |
Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 7,111 | 6,998 |
Derivative Asset, Fair Value, Gross Asset | 7,555 | 14,338 |
Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 638 | 234 |
Derivative Liability, Fair Value, Gross Liability | 205,013 | 79,302 |
Non Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 269 | 0 |
Derivative Liability, Fair Value, Gross Liability | 61,013 | 22,343 |
Rollfactor Derivative Contracts Related to Natural Gas and Crude Oil Sales [Member] [Member] | Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 11 | 0 |
Rollfactor Derivative Contracts Related to Natural Gas and Crude Oil Sales [Member] [Member] | Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 230 | 1,069 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 433 | 7,340 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Non Current Assets | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 3,949 | 0 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Liabilities | ||
Derivatives, Fair Value | ||
Fair Value of Derivatives | 204,145 | 77,999 |
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Non Current Liabilities | ||
Derivatives, Fair Value | ||
Derivative Liability, Fair Value, Gross Liability | $ 60,744 | $ 22,343 |
Impact of Derivative Instrument
Impact of Derivative Instruments on Statement of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative [Line Items] | ||||
Commodity price risk management gain (loss), net | $ (94,394) | $ (52,178) | $ (257,760) | $ 86,458 |
Commodity Price Risk Management (loss), net | ||||
Derivative [Line Items] | ||||
Commodity price risk management gain (loss), net | (48,096) | 9,585 | (90,542) | 22,151 |
Net change in fair value of unsettled derivatives | (46,298) | (61,763) | (167,218) | 64,307 |
Total commodity price risk management gain (loss), net | $ (94,394) | $ (52,178) | $ (257,760) | $ 86,458 |
Derivative Financial Instrume_3
Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value | ||
Gain on early settlement of derivative basis protection positions | $ 11,300 | |
Derivative Asset: | ||
Derivative assets, gross | (11,504) | $ (14,338) |
Effect of master netting agreements | 11,451 | 14,173 |
Derivative asset, net | 53 | 165 |
Derivative Liability: | ||
Derivative liability, gross | 266,026 | 101,645 |
Effect of master netting agreements | (11,451) | (14,173) |
Derivative liability, net | 254,575 | $ 87,472 |
Crude Oil [Member] | ||
Derivatives, Fair Value | ||
Gain on early settlement of derivative basis protection positions | 10,300 | |
Natural Gas [Member] | ||
Derivatives, Fair Value | ||
Gain on early settlement of derivative basis protection positions | $ 1,000 |
Derivative Financial Instrume_4
Derivative Financial Instruments Outstanding Derivative Contracts (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2018USD ($)MMBTU$ / UnitMBbls | |
Derivative [Line Items] | |
FV Commodity Derivatives Assets measured with Level 3 | 49.20% |
Derivative, Fair Value, Net | $ | $ (254,522) |
FV Commodity Derivatives Liabilities measured with Level 3 | 13.00% |
Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ (1,506) |
Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | (257,062) |
2018 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | (69,943) |
2019 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | (157,085) |
2020 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ (30,034) |
Columbia [Member] | Natural Gas [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.40 |
Columbia [Member] | Natural Gas [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.40 |
Dominion South [Member] | Natural Gas [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.12 |
Dominion South [Member] | Natural Gas [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.13 |
CMA [Member] | Crude Oil [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 0.14 |
Mont Belvieu [Member] | Propane [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 33.97 |
Waha [Member] | Natural Gas [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | (0.50) |
CIG [Member] | Natural Gas [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | (0.42) |
CIG [Member] | Natural Gas [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | (0.88) |
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.93 |
Derivative, Floor Price | 3 |
Derivative, Cap Price | 3.90 |
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 2.78 |
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 52.23 |
Derivative, Floor Price | 45.59 |
Derivative, Cap Price | 56.82 |
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2019 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 53.86 |
Derivative, Floor Price | 56.54 |
Derivative, Cap Price | 68.13 |
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2020 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | 62.07 |
Derivative, Floor Price | 55 |
Derivative, Cap Price | 71.68 |
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Crude Oil [Member] | 2018 | |
Derivative [Line Items] | |
Derivative, Swap Type, Average Fixed Price | (0.10) |
Columbia [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 0 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 3,000 |
Columbia [Member] | 2019 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 0 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 3,000 |
Commodity Option [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 120,000 |
Commodity Option [Member] | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 6,728 |
Commodity Option [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 120,000 |
Commodity Option [Member] | 2018 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 528 |
Commodity Option [Member] | 2019 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 0 |
Commodity Option [Member] | 2019 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 2,600 |
Commodity Option [Member] | 2020 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 3,600 |
CME SWAPS MARKETS (NYMEX) [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ (1,504) |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 14,145,000 |
CME SWAPS MARKETS (NYMEX) [Member] | 2019 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ (15) |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 8,004,000 |
Rollfactor - CMA [Member] | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 1,529 |
Derivative, Fair Value, Net | $ | $ (220) |
Rollfactor - CMA [Member] | 2018 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 1,529 |
Derivative, Fair Value, Net | $ | $ (220) |
Basis Protection Contracts Related to Natural Gas Marketing [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 4,491 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 19,443,000 |
Basis Protection - Waha [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 1,862 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 1,713,000 |
Basis Protection - CIG [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 3,537 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 9,806,000 |
Basis Protection - CIG [Member] | 2019 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ (908) |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 7,924,000 |
Basis Protection - Midland Cushing [Member] | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 182,000 |
Derivative, Fair Value, Net | $ | $ 1,713 |
Basis Protection - Midland Cushing [Member] | 2018 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 182,000 |
Derivative, Fair Value, Net | $ | $ 1,713 |
Energy Related Derivative [Member] | Propane [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 167 |
Derivative, Fair Value, Net | $ | $ (1,938) |
Energy Related Derivative [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 22,370,000 |
Energy Related Derivative [Member] | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 16,368 |
Energy Related Derivative [Member] | 2018 | Propane [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 167 |
Derivative, Fair Value, Net | $ | $ (1,938) |
Energy Related Derivative [Member] | 2018 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 2,968 |
Energy Related Derivative [Member] | 2019 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 8,400 |
Energy Related Derivative [Member] | 2020 | Crude Oil [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 5,000 |
Dominion South [Member] | 2018 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 6 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 94,000 |
Dominion South [Member] | 2019 | Natural Gas [Member] | |
Derivative [Line Items] | |
Derivative, Fair Value, Net | $ | $ 7 |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 121,000 |
Properties and Equipment (Detai
Properties and Equipment (Details) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018USD ($)Wells | Dec. 31, 2017USD ($)Wells | Sep. 30, 2017USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves | $ (43,145) | $ (36,328) | |
Proved Natural Gas and Crude Oil Properties | 5,204,267 | 4,356,922 | |
Unproved Natural Gas and Crude Oil Properties | 866,719 | 1,097,317 | |
Total Natural Gas and Crude Oil Properties | 6,070,986 | 5,454,239 | |
Equipment and other | 141,045 | 109,359 | |
Land and Buildings | 12,544 | 10,960 | |
Construction in Progress | 318,949 | 196,024 | |
Properties and equipment, at cost | 6,543,524 | 5,770,582 | |
Accumulated DD&A | (2,234,503) | (1,837,115) | |
Property, Plant and Equipment, Net | 4,309,021 | 3,933,467 | |
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves | 29,203 | 51,776 | |
Capitalized Exploratory Well Costs | $ 1,506 | $ 15,448 | $ 0 |
Wells to be completed | Wells | 1 | 3 |
Impairment of Natural Gas and C
Impairment of Natural Gas and Crude Oil Properties (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | |
Impairment of natural gas and crude oil properties [Line Items] | ||||
Impairment of properties and equipment | $ 1,488 | $ 252,740 | $ 194,230 | $ 282,499 |
Impairment of Leasehold | 1,488 | 252,623 | 194,146 | 282,188 |
Delaware Basin Unproved Property Impairment | 6,300 | |||
Amortization of Individually Insignificant Unproved Properties | 0 | 117 | 84 | 311 |
Impairment of Oil and Gas Properties | $ 1,488 | $ 252,740 | 194,230 | 282,499 |
Impairment of properties and equipment | $ 194,230 | $ 282,499 | ||
Delaware Basin [Member] | ||||
Impairment of natural gas and crude oil properties [Line Items] | ||||
Viable drilling locations, not impaired | 450 | 450 |
Properties and Equipment Acreag
Properties and Equipment Acreage exchange (Details) $ in Millions | Sep. 30, 2018USD ($)a |
Third Party 2 acreage to PDC [Member] | |
Gas and Oil Acreage [Line Items] | |
Gas and Oil Area, Developed, Gross | 2,500 |
Cash, additional to acreage, received | $ | $ 3.7 |
PDC acreage to Third Party 1 [Member] [Member] | |
Gas and Oil Acreage [Line Items] | |
Gas and Oil Area, Developed, Gross | 2,600 |
Properties and Equipment Assets
Properties and Equipment Assets Held for Sale (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Long Lived Assets Held-for-sale [Line Items] | |||||
Impairment of properties and equipment | $ 1,488 | $ 252,740 | $ 194,230 | $ 282,499 | |
Proceeds from Sale of Property Held-for-sale | 39,000 | ||||
(Gain) loss on sale of properties and equipment | 3,199 | (754) | |||
Properties and equipment, net | 4,309,021 | 4,309,021 | $ 3,933,467 | ||
Assets | 4,601,224 | 4,601,224 | 4,419,891 | ||
Asset retirement obligations | 72,707 | 72,707 | 71,006 | ||
Liabilities | $ 2,258,980 | 2,258,980 | $ 1,912,242 | ||
Proceeds from sale of properties and equipment | 2,443 | $ 3,322 | |||
Utica Shale [Member] | |||||
Long Lived Assets Held-for-sale [Line Items] | |||||
(Gain) loss on sale of properties and equipment | $ 1,400 |
Other Accrued Expenses Other _3
Other Accrued Expenses Other Accrued Expenses (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Schedule of Other Liabilities [Line Items] | ||||
Saddle Butte Rockies Midstream Amendment Payment | $ 24,100 | |||
Amortization of Other Deferred Charges | $ 400 | 1,100 | ||
Production Tax Liability | 44,817 | 44,817 | $ 50,476 | |
Other Accrued Liabilities, Noncurrent | 76,987 | 76,987 | 57,333 | |
Non Current Liabilities | ||||
Schedule of Other Liabilities [Line Items] | ||||
Increase (Decrease) in Accrued Cost of Oil and Gas Reclamation | 22,613 | $ 0 | ||
Other Accrued Liabilities | 9,557 | 9,557 | 6,857 | |
Current Liabilities | ||||
Schedule of Other Liabilities [Line Items] | ||||
Other Accrued Liabilities | $ 3,284 | $ 3,284 | $ 3,429 |
Other Accrued Expenses Schedule
Other Accrued Expenses Schedule of Other Accrued Expense (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Schedule of Other Accrued Expense [Line Items] | ||
Accrued Employee Benefits, Current | $ 16,555 | $ 22,383 |
Asset Retirement Obligation, Current | 16,006 | 15,801 |
Accrued Environmental Loss Contingencies, Current | 3,415 | 1,374 |
Other accrued expenses | 39,260 | 42,987 |
Current Liabilities | ||
Schedule of Other Accrued Expense [Line Items] | ||
Other Accrued Liabilities | 3,284 | 3,429 |
Non Current Liabilities | ||
Schedule of Other Accrued Expense [Line Items] | ||
Other Accrued Liabilities | $ 9,557 | $ 6,857 |
Schedule of Long-Term Debt (Det
Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Nov. 14, 2017 | Sep. 14, 2016 |
Debt Instrument | ||||
Total senior notes | $ 1,159,733 | $ 1,151,932 | ||
Total debt, net of discount and unamortized debt issuance costs | 1,234,733 | 1,151,932 | ||
Long-term debt | 1,234,733 | 1,151,932 | ||
1.125% Convertible Senior Notes due 2021 [Member] | ||||
Debt Instrument | ||||
Principal amount | 200,000 | 200,000 | ||
Unamortized Discount | (24,697) | (30,328) | ||
Unamortized Debt Issuance Expense | (2,884) | (3,615) | $ (4,800) | |
Convertible senior notes net of discount | 172,419 | 166,057 | ||
5.75% Senior Notes due 2026 [Member] | ||||
Debt Instrument | ||||
Unamortized Debt Issuance Expense | (6,851) | (7,555) | ||
Principal amount | 600,000 | 600,000 | $ 7,600 | |
Senior notes, net of unamortized debt issuance costs | 593,149 | 592,445 | ||
6.125% Senior Notes due 2024 [Member] | ||||
Debt Instrument | ||||
Unamortized Debt Issuance Expense | (5,835) | (6,570) | $ (7,800) | |
Principal amount | 400,000 | 400,000 | ||
Senior notes, net of unamortized debt issuance costs | 394,165 | 393,430 | ||
Revolving Credit Facility | ||||
Debt Instrument | ||||
Revolving credit facility | $ 75,000 | $ 0 |
Long-Term Debt Additional Infor
Long-Term Debt Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands | Sep. 12, 2016 | Sep. 30, 2018 | Oct. 04, 2018 | Dec. 31, 2017 | Sep. 14, 2016 |
Debt Instrument | |||||
Convertible Note, Conversion Price | $ 85.39 | ||||
Debt Instrument, Maturity Date | Sep. 15, 2021 | ||||
Line of Credit Facility, Initial Borrowing Base | $ 1,300,000 | $ 1,300,000 | |||
Line of Credit, Initial Elected Commitment | 700,000 | ||||
Debt Issuance Costs, Line of Credit Arrangements, Net | 8,600 | $ 6,200 | |||
Swingline Facility | $ 25,000 | ||||
Line of Credit Facility, Weighted Average Interest Rate | 4.20% | ||||
5.75% Senior Notes due 2026 [Member] | |||||
Debt Instrument | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | ||||
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 | ||||
Revolving Credit Facility | |||||
Debt Instrument | |||||
Line of Credit Facility, Expiration Date | May 23, 2023 | ||||
Maximum Borrowing Base [Member] | Revolving Credit Facility | |||||
Debt Instrument | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,500,000 | ||||
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 | ||||
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 | ||||
Revolving Credit Facility | |||||
Debt Instrument | |||||
Long-term Line of Credit | $ 75,000 | 0 | |||
1.125% Convertible Senior Notes due 2021 [Member] | |||||
Debt Instrument | |||||
Convertible senior notes fair value | $ 200,000 | 200,000 | |||
Convertible Note, Conversion Price | $ 85.39 | ||||
Liability component of gross proceeds of Convertible Notes | $ 160,500 | ||||
Unamortized Debt Issuance Expense | (2,884) | (3,615) | $ (4,800) | ||
6.125% Senior Notes due 2024 [Member] | |||||
Debt Instrument | |||||
Unamortized Debt Issuance Expense | (5,835) | (6,570) | $ (7,800) | ||
Senior Notes ($) | $ 400,000 | $ 400,000 | |||
Alternate Base Rate Option [Member] | |||||
Debt Instrument | |||||
Line of Credit Facility, Interest Rate at Period End | 0.25% | ||||
LIBOR Option [Member] | |||||
Debt Instrument | |||||
Line of Credit Facility, Interest Rate at Period End | 1.25% | ||||
Unused Commitment Fee [Member] | |||||
Debt Instrument | |||||
Line of Credit Facility, Interest Rate at Period End | 0.375% |
Capital Leases Capital Leases (
Capital Leases Capital Leases (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Capital Leased Assets [Line Items] | ||
Vehicles | $ 7,255 | $ 6,249 |
Accumulated Depreciation | (2,931) | (1,882) |
Capital Leased Assets, Net | $ 4,324 | $ 4,367 |
Capital Leases Minimum Lease Pa
Capital Leases Minimum Lease Payments (Details) $ in Thousands | Sep. 30, 2018USD ($) |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 5,426 |
Executory Costs | (260) |
Amount representing interest | (551) |
Present Value of Net Minimum Payments | 4,615 |
Short-term Capital Lease Obligations | 1,897 |
Long-Term Capital Lease Obligations | 2,718 |
Total Capital Lease Obligations | 4,615 |
2,019 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 2,165 |
2,020 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 2,427 |
2,021 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 583 |
2022 [Member] | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 138 |
2023 [Member] | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 113 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | ||||
Effective Income Tax Rate, Continuing Operations | 53.00% | 29.50% | 23.30% | 25.80% |
Other Tax Expense (Benefit) | $ 2.6 | |||
Other Deductions or Allowable Credits | $ 1.5 | $ 1.5 | ||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 12.30% | 0.50% | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis | |||||
Balance at beginning of period | $ 87,306 | ||||
Obligations incurred with development activities | 2,147 | ||||
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | $ 4,326 | 4,326 | |||
Accretion expense | 1,200 | $ 1,472 | 3,773 | $ 4,906 | |
Asset Retirement Obligation, Revision of Estimate | 754 | ||||
Obligations discharged asset retirements | (9,593) | ||||
Balance end of period | 88,713 | 88,713 | |||
Less current portion | (16,006) | (16,006) | $ (15,801) | ||
Asset retirement obligations | $ 72,707 | $ 72,707 | $ 71,006 |
Commitments and Contingencies_2
Commitments and Contingencies Commitments and Contigencies (Details) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2018USD ($)MBblsMMcf | Sep. 30, 2018USD ($)MBblsbblMMcf | Oct. 23, 2018USD ($) | |
Supply Commitment | |||
AOC penalty | $ | $ 130,000 | ||
Dollar Commitment ($ in thousands) | $ | $ 461,996,000 | $ 461,996,000 | |
AOC penalty suspended percentage | 20.00% | ||
Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 27,598 | 27,598 | |
Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 210,759 | 210,759 | |
Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 120,214 | 120,214 | |
First Year Commitment [Member] | |||
Supply Commitment | |||
Dollar Commitment ($ in thousands) | $ | $ 92,736,000 | $ 92,736,000 | |
First Year Commitment [Member] | Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,117 | 7,117 | |
First Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 19,142 | 19,142 | |
First Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 48,387 | 48,387 | |
Second Year Commitment [Member] | |||
Supply Commitment | |||
Dollar Commitment ($ in thousands) | $ | $ 87,056,000 | $ 87,056,000 | |
Second Year Commitment [Member] | Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,136 | 7,136 | |
Second Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 30,850 | 30,850 | |
Second Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 41,426 | 41,426 | |
Third Year Commitment [Member] | |||
Supply Commitment | |||
Dollar Commitment ($ in thousands) | $ | $ 72,476,000 | $ 72,476,000 | |
Third Year Commitment [Member] | Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,117 | 7,117 | |
Third Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,025 | 31,025 | |
Third Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 25,075 | 25,075 | |
Fourth Year Commitment [Member] | |||
Supply Commitment | |||
Dollar Commitment ($ in thousands) | $ | $ 71,457,000 | $ 71,457,000 | |
Fourth Year Commitment [Member] | Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,228 | 6,228 | |
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) | 5,326 | 5,326 | |
commitments 5 years and beyond [Member] | |||
Supply Commitment | |||
Dollar Commitment ($ in thousands) | $ | $ 138,271,000 | $ 138,271,000 | |
commitments 5 years and beyond [Member] | Appalachiain Basin | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 0 | 0 | |
commitments 5 years and beyond [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 98,717 | 98,717 | |
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] | Wattenberg Field | |||
Supply Commitment | |||
Supply Commitments Contract Expiration Date | Apr. 30, 2026 | ||
Supply Contract Expiration Date [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Supply Commitments Contract Expiration Date | Dec. 31, 2021 | ||
Crude Oil [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 29,320 | 29,320 | |
Crude Oil [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 41,782 | 41,782 | |
Crude Oil [Member] | First Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 7,888 | 7,888 | |
Crude Oil [Member] | First Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,651 | 6,651 | |
Crude Oil [Member] | Second Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 7,302 | 7,302 | |
Crude Oil [Member] | Second Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,833 | 8,833 | |
Crude Oil [Member] | Third Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 5,475 | 5,475 | |
Crude Oil [Member] | Third Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,214 | 8,214 | |
Crude Oil [Member] | Fourth Year Commitment [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 5,475 | 5,475 | |
Crude Oil [Member] | Fourth Year Commitment [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,030 | 8,030 | |
Crude Oil [Member] | commitments 5 years and beyond [Member] | Wattenberg Field | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 3,180 | 3,180 | |
Crude Oil [Member] | commitments 5 years and beyond [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 10,054 | 10,054 | |
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Wattenberg Field | |||
Supply Commitment | |||
Supply Commitments Contract Expiration Date | Apr. 30, 2023 | ||
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Supply Commitments Contract Expiration Date | Dec. 31, 2023 | ||
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 | ||
Natural Gas [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 358,571 | 358,571 | |
Natural Gas [Member] | First Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 74,646 | 74,646 | |
Natural Gas [Member] | Second Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 79,412 | 79,412 | |
Natural Gas [Member] | Third Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 63,217 | 63,217 | |
Natural Gas [Member] | Fourth Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 42,579 | 42,579 | |
Natural Gas [Member] | commitments 5 years and beyond [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 98,717 | 98,717 | |
Crude Oil [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 71,102 | 71,102 | |
Crude Oil [Member] | First Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 14,539 | 14,539 | |
Crude Oil [Member] | Second Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 16,135 | 16,135 | |
Crude Oil [Member] | Third Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 13,689 | 13,689 | |
Crude Oil [Member] | Fourth Year Commitment [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 13,505 | 13,505 | |
Crude Oil [Member] | commitments 5 years and beyond [Member] | |||
Supply Commitment | |||
Oil and Gas Delivery Commitments Volumes (MMcf) | 13,234 | 13,234 | |
Minimum [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Committed Barrels of Crude Oil per day | bbl | 11,400 | ||
Maximum [Member] | Delaware Basin [Member] | |||
Supply Commitment | |||
Committed Barrels of Crude Oil per day | bbl | 26,400 |
Commitments and Contingencies A
Commitments and Contingencies Additional information (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)MMcf | Sep. 30, 2017USD ($) | |
Loss Contingencies [Line Items] | ||||
Results of Operations, Transportation Costs | $ 9,234 | $ 9,794 | $ 25,511 | $ 22,184 |
First facilities agreement with midstream provider [Member] | ||||
Loss Contingencies [Line Items] | ||||
incremental volume commitment | MMcf | 51.5 | |||
Delaware Basin/Wattenberg Field [Member] | ||||
Loss Contingencies [Line Items] | ||||
Results of Operations, Transportation Costs | 11,000 | $ 16,200 | ||
Utica Shale natural gas and Wattenberg Field crude oil [Member] | ||||
Loss Contingencies [Line Items] | ||||
Results of Operations, Transportation Costs | $ 800 | $ 2,600 | $ 7,400 |
Commitments and Contingencies N
Commitments and Contingencies New Plant (Details) | 9 Months Ended |
Sep. 30, 2018 | |
Natural Gas [Member] | |
Property, Plant and Equipment [Line Items] | |
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments | 200 |
Commitments and Contingencies_3
Commitments and Contingencies Clean Air Act (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Obligation with Joint and Several Liability Arrangement [Line Items] | |
Supplemental environmental legal expense paid | $ 1.5 |
Supplemental environment projects legal expense | 1 |
Injunctive relief legal expense accrual | 18 |
Mitigation legal expense accrual | $ 1.7 |
Common Stock Sale of Common Sto
Common Stock Sale of Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Class of Stock [Line Items] | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common shares - par value | $ 661 | $ 659 |
Additional paid-in capital | $ 2,514,861 | $ 2,503,294 |
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, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs | ||||
Common Stock, Capital Shares Reserved for Future Issuance | 1,800,000 | 1,800,000 | ||
Common stock shares remain avaliable for issuance | 233,783 | 233,783 | ||
Stock-based compensation expense | $ 5,578 | $ 4,761 | $ 16,357 | $ 14,587 |
Income tax benefit | (1,337) | (1,781) | (3,921) | (5,457) |
Net stock-based compensation expense | $ 4,241 | $ 2,980 | $ 12,436 | $ 9,130 |
Schedule of Changes in SARs (De
Schedule of Changes in SARs (Details) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018USD ($)shares | Sep. 30, 2018USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period | 7,962 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 0 | |
Stock Appreciation Rights (SARs) | ||
Share based compesation aggregate intrinsic value | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ | $ 0.9 | $ 0.9 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 10 months 24 days |
Schedule of Changes in Restrict
Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2017 | Sep. 30, 2018 | |
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 RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs 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, | 472,132 | |
Granted | 416,687 | |
Vested | (219,768) | |
Forfeited | (36,137) | |
Outstanding at period end, | 632,914 | |
Weighted-Average Grant-Date Fair Value | ||
Outstanding at beginning of year, January 1, | $ 60.23 | |
Granted | $ 66 | 50.85 |
Vested | 58.26 | |
Forfeited | 57.22 | |
Outstanding at period end, | $ 54.91 | |
Total intrinsic value of time based awards vested | $ 13,266 | $ 11,178 |
Total intrinsic value of time-based awards non-vested | $ 25,762 | $ 30,987 |
Market price per common share as of period end, | $ 49.03 | $ 48.96 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 24,500 | |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 months 21 days |
Restricted Stock - Market Based
Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - $ / shares | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Restricted Stock - Market Based Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Expected term of award | 3 years | 3 years | |
Risk-free interest rate | 1.40% | 2.40% | |
Expected Volatility | 51.40% | 42.30% | |
Granted | $ 69.98 | $ 94.02 | |
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Performance Shares Payout Range | 0.00% | ||
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Performance Shares Payout Range | 200.00% |
Schedule of Changes in Restri_2
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, 2018 | Sep. 30, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Forfeited | (4,128) | |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the market-based PSUs 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 | 90,778 | |
Number of Shares | ||
Outstanding beginning of year, January 1, | 52,349 | |
Granted | 90,778 | |
Outstanding at period end, | 138,999 | |
Weighted-Average Grant-Date Fair Value | ||
Outstanding at beginning of year, January 1, | $ 84.06 | |
Granted | 69.98 | $ 94.02 |
Outstanding at period end, | $ 74.57 | |
Total intrinsic value of market-based awards non-vested | $ 6,805 | $ 3,750 |
Market price per common share as of period end, | $ 48.96 | $ 49.03 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 6,100 | |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 8 months 23 days | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ 94.02 |
Common Stock Preferred Stock (D
Common Stock Preferred Stock (Details) - shares | Sep. 30, 2018 | Dec. 31, 2017 | 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 | Sep. 30, 2018 | Dec. 31, 2017 |
Share-based Compensation Arrangement by Share-based Payment Award | ||
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Earnings Per Share (Details)
Earnings Per Share (Details) - $ / shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reconciliation of Weighted-Average Diluted Shares Outstanding | ||||
Weighted average common shares outstanding - basic | 66,073,000 | 65,865,000 | 66,032,000 | 65,825,000 |
Pro Forma Weighted Average Shares Outstanding, Diluted | 66,073,000 | 65,865,000 | 66,032,000 | 65,825,000 |
Anti-dilutive Effect | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 1,033,000 | 636,000 | 974,000 | 667,000 |
Convertible Senior Note | ||||
Convertible Note, Shares To Be Received Upon Conversion (in thousands) | 2,300,000 | |||
Convertible Note, Conversion Price | $ 85.39 | $ 85.39 | ||
Restricted stock | ||||
Anti-dilutive Effect | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 719,000 | 588,000 | 655,000 | 585,000 |
Other equity-based awards | ||||
Anti-dilutive Effect | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 314,000 | 48,000 | 319,000 | 82,000 |
Subsidiary Guarantor Condensed
Subsidiary Guarantor Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Cash and cash equivalents | $ 1,369 | $ 180,675 | $ 136,429 |
Accounts receivable, net | 241,155 | 197,598 | |
Fair value of derivatives | 7,555 | 14,338 | |
Prepaid expenses and other current assets | 6,713 | 8,613 | |
Total current assets | 256,792 | 401,224 | |
Properties and equipment, net | 4,309,021 | 3,933,467 | |
Assets held-for-sale, net | 0 | 40,084 | |
Intercompany Receivables | 0 | 0 | |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 0 | 0 | |
Derivative Instruments and Hedges, Noncurrent | 3,949 | 0 | |
Other assets | 31,462 | 45,116 | |
Total Assets | 4,601,224 | 4,419,891 | |
Accounts payable | 251,081 | 150,067 | |
Production tax liability | 59,539 | 37,654 | |
Fair value of derivatives | 205,013 | 79,302 | |
Funds held for distribution | 104,259 | 95,811 | |
Accrued interest payable | 15,425 | 11,815 | |
Other accrued expenses | 39,260 | 42,987 | |
Total current liabilities | 674,577 | 417,636 | |
Intercompany Payable | 0 | 0 | |
Long-term debt | 1,234,733 | 1,151,932 | |
Deferred income taxes | 138,963 | 191,992 | |
Asset retirement obligations | 72,707 | 71,006 | |
Fair value of derivatives | 61,013 | 22,343 | |
Other liabilities | 76,987 | 57,333 | |
Total liabilities | 2,258,980 | 1,912,242 | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively | 661 | 659 | |
Additional paid-in capital | 2,514,861 | 2,503,294 | |
Retained earnings (deficit) | (170,126) | 6,704 | |
Treasury Stock, Value | 3,152 | 3,008 | |
Total stockholders' equity | 2,342,244 | 2,507,649 | |
Total Liabilities and Stockholders' Equity | 4,601,224 | 4,419,891 | |
Corporate, Non-Segment [Member] | |||
Cash and cash equivalents | 1,369 | 180,675 | |
Accounts receivable, net | 186,274 | 160,490 | |
Fair value of derivatives | 7,555 | 14,338 | |
Prepaid expenses and other current assets | 5,983 | 8,284 | |
Total current assets | 201,181 | 363,787 | |
Properties and equipment, net | 2,216,649 | 1,891,314 | |
Assets held-for-sale, net | 40,084 | ||
Intercompany Receivables | 404,641 | 250,279 | |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 1,504,791 | 1,617,537 | |
Derivative Instruments and Hedges, Noncurrent | 3,949 | ||
Other assets | 26,327 | 42,547 | |
Total Assets | 4,357,538 | 4,205,548 | |
Accounts payable | 135,264 | 85,000 | |
Production tax liability | 53,573 | 35,902 | |
Fair value of derivatives | 205,013 | 79,302 | |
Funds held for distribution | 86,173 | 83,898 | |
Accrued interest payable | 15,419 | 11,812 | |
Other accrued expenses | 38,366 | 42,543 | |
Total current liabilities | 533,808 | 338,457 | |
Intercompany Payable | 0 | 0 | |
Long-term debt | 1,234,733 | 1,151,932 | |
Deferred income taxes | 44,066 | 62,857 | |
Asset retirement obligations | 65,248 | 65,301 | |
Fair value of derivatives | 61,013 | 22,343 | |
Other liabilities | 76,426 | 57,009 | |
Total liabilities | 2,015,294 | 1,697,899 | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively | 661 | 659 | |
Additional paid-in capital | 2,514,861 | 2,503,294 | |
Retained earnings (deficit) | (170,126) | 6,704 | |
Treasury Stock, Value | 3,152 | 3,008 | |
Total stockholders' equity | 2,342,244 | 2,507,649 | |
Total Liabilities and Stockholders' Equity | 4,357,538 | 4,205,548 | |
Reportable Legal Entities [Member] | |||
Cash and cash equivalents | 0 | 0 | |
Accounts receivable, net | 54,881 | 37,108 | |
Fair value of derivatives | 0 | 0 | |
Prepaid expenses and other current assets | 730 | 329 | |
Total current assets | 55,611 | 37,437 | |
Properties and equipment, net | 2,092,372 | 2,042,153 | |
Assets held-for-sale, net | 0 | ||
Intercompany Receivables | 0 | 0 | |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 0 | 0 | |
Derivative Instruments and Hedges, Noncurrent | 0 | ||
Other assets | 5,135 | 2,569 | |
Total Assets | 2,153,118 | 2,082,159 | |
Accounts payable | 115,817 | 65,067 | |
Production tax liability | 5,966 | 1,752 | |
Fair value of derivatives | 0 | 0 | |
Funds held for distribution | 18,086 | 11,913 | |
Accrued interest payable | 6 | 3 | |
Other accrued expenses | 894 | 444 | |
Total current liabilities | 140,769 | 79,179 | |
Intercompany Payable | 404,641 | 250,279 | |
Long-term debt | 0 | 0 | |
Deferred income taxes | 94,897 | 129,135 | |
Asset retirement obligations | 7,459 | 5,705 | |
Fair value of derivatives | 0 | 0 | |
Other liabilities | 561 | 324 | |
Total liabilities | 648,327 | 464,622 | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively | 0 | 0 | |
Additional paid-in capital | 1,766,775 | 1,766,775 | |
Retained earnings (deficit) | (261,984) | (149,238) | |
Treasury Stock, Value | 0 | 0 | |
Total stockholders' equity | 1,504,791 | 1,617,537 | |
Total Liabilities and Stockholders' Equity | 2,153,118 | 2,082,159 | |
Consolidation, Eliminations [Member] | |||
Cash and cash equivalents | 0 | 0 | |
Accounts receivable, net | 0 | 0 | |
Fair value of derivatives | 0 | 0 | |
Prepaid expenses and other current assets | 0 | 0 | |
Total current assets | 0 | 0 | |
Properties and equipment, net | 0 | 0 | |
Assets held-for-sale, net | 0 | ||
Intercompany Receivables | (404,641) | (250,279) | |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | (1,504,791) | (1,617,537) | |
Derivative Instruments and Hedges, Noncurrent | 0 | ||
Other assets | 0 | 0 | |
Total Assets | (1,909,432) | (1,867,816) | |
Accounts payable | 0 | 0 | |
Production tax liability | 0 | 0 | |
Fair value of derivatives | 0 | 0 | |
Funds held for distribution | 0 | 0 | |
Accrued interest payable | 0 | 0 | |
Other accrued expenses | 0 | 0 | |
Total current liabilities | 0 | 0 | |
Intercompany Payable | (404,641) | (250,279) | |
Long-term debt | 0 | 0 | |
Deferred income taxes | 0 | 0 | |
Asset retirement obligations | 0 | 0 | |
Fair value of derivatives | 0 | 0 | |
Other liabilities | 0 | 0 | |
Total liabilities | (404,641) | (250,279) | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,136,427 and 65,955,080 issued as of September 30, 2018 and December 31, 2017, respectively | 0 | 0 | |
Additional paid-in capital | (1,766,775) | (1,766,775) | |
Retained earnings (deficit) | 261,984 | 149,238 | |
Treasury Stock, Value | 0 | 0 | |
Total stockholders' equity | (1,504,791) | (1,617,537) | |
Total Liabilities and Stockholders' Equity | $ (1,909,432) | $ (1,867,816) |
Subsidiary Guarantor Condense_2
Subsidiary Guarantor Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Mar. 31, 2016 | Sep. 30, 2018 | Sep. 30, 2017 | |
Crude oil, natural gas and NGLs sales | $ 372,439 | $ 232,733 | $ 1,003,597 | $ 636,027 | |
Proceeds from Sale of Short-term Investments | 0 | 49,890 | |||
Commodity price risk management gain (loss), net | (94,394) | (52,178) | (257,760) | 86,458 | |
Other income | 2,672 | 2,680 | 8,011 | 9,615 | |
Revenues | 280,717 | 183,235 | 753,848 | 732,100 | |
Lease operating expenses | 33,046 | 25,353 | 94,942 | 65,170 | |
Production taxes | 23,984 | 15,516 | 66,757 | 42,957 | |
Transportation, gathering and processing expenses | 9,234 | 9,794 | 25,511 | 22,184 | |
Exploration, geologic and geophysical expense | 1,032 | 41,908 | 4,553 | 43,895 | |
Impairment of properties and equipment | 1,488 | 252,740 | 194,230 | 282,499 | |
Goodwill, Impairment Loss | 0 | 75,121 | 0 | 75,121 | |
General and administrative expense | 48,240 | 29,299 | 121,183 | 85,145 | |
Results of Operations, Depreciation, Depletion, Amortization and Accretion | 147,540 | 125,238 | 409,952 | 360,567 | |
Accretion of asset retirement obligations | 1,200 | 1,472 | 3,773 | 4,906 | |
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | 2,118 | (62) | 3,199 | (754) | |
Provision for uncollectible note receivable | 0 | 0 | $ 44,000 | 0 | (40,203) |
Other Cost and Expense, Operating | 2,711 | 2,947 | 8,187 | 10,365 | |
Costs and Expenses | 270,593 | 579,326 | 932,287 | 951,852 | |
Operating Income (Loss) | 10,124 | (396,091) | (178,439) | (219,752) | |
Interest Expense | 17,622 | 19,275 | 52,561 | 58,359 | |
Interest income | 188 | 479 | 405 | 1,487 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (7,310) | (414,887) | (230,595) | (276,624) | |
Income tax (expense) benefit | 3,876 | 122,350 | 53,765 | 71,483 | |
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | 0 | 0 | |
Net Income (Loss) Attributable to Parent | (3,434) | (292,537) | (176,830) | (205,141) | |
Corporate, Non-Segment [Member] | |||||
Crude oil, natural gas and NGLs sales | 280,866 | 199,565 | 757,263 | 561,132 | |
Commodity price risk management gain (loss), net | (94,394) | (52,178) | (257,760) | 86,458 | |
Other income | 2,300 | 2,628 | 7,295 | 9,512 | |
Revenues | 188,772 | 150,015 | 506,798 | 657,102 | |
Lease operating expenses | 23,219 | 18,181 | 68,013 | 49,555 | |
Production taxes | 17,852 | 13,467 | 50,122 | 38,000 | |
Transportation, gathering and processing expenses | 4,520 | 5,970 | 11,361 | 16,953 | |
Exploration, geologic and geophysical expense | 279 | 216 | 887 | 744 | |
Impairment of properties and equipment | 98 | 1,148 | 191 | 2,282 | |
Goodwill, Impairment Loss | 0 | 0 | |||
General and administrative expense | 43,886 | 26,207 | 108,597 | 76,353 | |
Results of Operations, Depreciation, Depletion, Amortization and Accretion | 97,370 | 106,623 | 284,963 | 317,088 | |
Accretion of asset retirement obligations | 1,084 | 1,386 | 3,460 | 4,660 | |
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | (141) | (62) | 940 | (754) | |
Provision for uncollectible note receivable | (40,203) | ||||
Other Cost and Expense, Operating | 2,711 | 2,947 | 8,187 | 10,365 | |
Costs and Expenses | 190,878 | 176,083 | 536,721 | 475,043 | |
Operating Income (Loss) | (2,106) | (26,068) | (29,923) | 182,059 | |
Interest Expense | 18,232 | 19,647 | 54,244 | 59,044 | |
Interest income | 188 | 479 | 405 | 1,487 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (20,150) | (45,236) | (83,762) | 124,502 | |
Income tax (expense) benefit | 5,753 | 30,274 | 19,678 | (32,174) | |
Income (Loss) from Subsidiaries, Net of Tax | 10,963 | (277,575) | (112,746) | (297,469) | |
Net Income (Loss) Attributable to Parent | (3,434) | (292,537) | (176,830) | (205,141) | |
Reportable Legal Entities [Member] | |||||
Crude oil, natural gas and NGLs sales | 91,573 | 33,168 | 246,334 | 74,895 | |
Commodity price risk management gain (loss), net | 0 | 0 | 0 | 0 | |
Other income | 372 | 52 | 716 | 103 | |
Revenues | 91,945 | 33,220 | 247,050 | 74,998 | |
Lease operating expenses | 9,827 | 7,172 | 26,929 | 15,615 | |
Production taxes | 6,132 | 2,049 | 16,635 | 4,957 | |
Transportation, gathering and processing expenses | 4,714 | 3,824 | 14,150 | 5,231 | |
Exploration, geologic and geophysical expense | 753 | 41,692 | 3,666 | 43,151 | |
Impairment of properties and equipment | 1,390 | 251,592 | 194,039 | 280,217 | |
Goodwill, Impairment Loss | 75,121 | 75,121 | |||
General and administrative expense | 4,354 | 3,092 | 12,586 | 8,792 | |
Results of Operations, Depreciation, Depletion, Amortization and Accretion | 50,170 | 18,615 | 124,989 | 43,479 | |
Accretion of asset retirement obligations | 116 | 86 | 313 | 246 | |
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | 2,259 | 0 | 2,259 | 0 | |
Provision for uncollectible note receivable | 0 | ||||
Other Cost and Expense, Operating | 0 | 0 | 0 | 0 | |
Costs and Expenses | 79,715 | 403,243 | 395,566 | 476,809 | |
Operating Income (Loss) | 12,230 | (370,023) | (148,516) | (401,811) | |
Interest Expense | 610 | 372 | 1,683 | 685 | |
Interest income | 0 | 0 | 0 | 0 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 12,840 | (369,651) | (146,833) | (401,126) | |
Income tax (expense) benefit | (1,877) | 92,076 | 34,087 | 103,657 | |
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | 0 | 0 | |
Net Income (Loss) Attributable to Parent | 10,963 | (277,575) | (112,746) | (297,469) | |
Consolidation, Eliminations [Member] | |||||
Crude oil, natural gas and NGLs sales | 0 | 0 | 0 | 0 | |
Proceeds from Sale of Short-term Investments | 0 | ||||
Commodity price risk management gain (loss), net | 0 | 0 | 0 | 0 | |
Other income | 0 | 0 | 0 | 0 | |
Revenues | 0 | 0 | 0 | 0 | |
Lease operating expenses | 0 | 0 | 0 | 0 | |
Production taxes | 0 | 0 | 0 | 0 | |
Transportation, gathering and processing expenses | 0 | 0 | 0 | 0 | |
Exploration, geologic and geophysical expense | 0 | 0 | 0 | 0 | |
Impairment of properties and equipment | 0 | 0 | 0 | 0 | |
Goodwill, Impairment Loss | 0 | 0 | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Results of Operations, Depreciation, Depletion, Amortization and Accretion | 0 | 0 | 0 | 0 | |
Accretion of asset retirement obligations | 0 | 0 | 0 | 0 | |
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | 0 | 0 | 0 | 0 | |
Provision for uncollectible note receivable | 0 | ||||
Other Cost and Expense, Operating | 0 | 0 | 0 | 0 | |
Costs and Expenses | 0 | 0 | 0 | 0 | |
Operating Income (Loss) | 0 | 0 | 0 | 0 | |
Interest Expense | 0 | 0 | 0 | 0 | |
Interest income | 0 | 0 | 0 | 0 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 0 | 0 | 0 | 0 | |
Income tax (expense) benefit | 0 | 0 | 0 | 0 | |
Income (Loss) from Subsidiaries, Net of Tax | (10,963) | 277,575 | 112,746 | 297,469 | |
Net Income (Loss) Attributable to Parent | $ (10,963) | $ 277,575 | $ 112,746 | $ 297,469 |
Subsidiary Guarantor Condense_3
Subsidiary Guarantor Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Net Cash Provided by (Used in) Operating Activities | $ 577,834 | $ 420,652 |
Payments to Explore and Develop Oil and Gas Properties | (685,549) | (528,850) |
Payments for Capital Improvements | (3,739) | (3,740) |
Payments to Acquire Businesses, Net of Cash Acquired | (181,572) | (14,482) |
Proceeds from sale of properties and equipment | 2,443 | 3,322 |
Proceeds from Sale of Notes Receivable | 0 | 40,203 |
Proceeds from divestiture | 43,493 | 0 |
Purchases of short-term investments | 0 | (49,890) |
Increase (Decrease) in Restricted Cash | 1,249 | (9,250) |
Proceeds from Sale of Short-term Investments | 0 | 49,890 |
intercompany Transfer Investing Activities | 0 | 0 |
Net Cash Provided by (Used in) Investing Activities | (823,675) | (512,797) |
Proceeds from Lines of Credit | 629,000 | |
Repayment of revolving credit facility | (554,000) | 0 |
Payments of Debt Issuance Costs | (4,086) | 0 |
Treasury Stock, Value, Acquired, Cost Method | (4,700) | (5,325) |
Other | (928) | (951) |
Intercompany Transfers Financing Activities | 0 | 0 |
Net Cash Provided by (Used in) Financing Activities | 65,286 | (6,276) |
Net change in cash, cash equivalents, and restricted cash | (180,555) | (98,421) |
Cash, cash equivalents and restricted cash, beginning of period | 189,925 | 244,100 |
Cash, cash equivalents and restricted cash, end of period | 9,370 | 145,679 |
Corporate, Non-Segment [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 405,326 | 391,965 |
Payments to Explore and Develop Oil and Gas Properties | (360,457) | (315,718) |
Payments for Capital Improvements | (2,834) | (2,488) |
Payments to Acquire Businesses, Net of Cash Acquired | (181,501) | (19,761) |
Proceeds from sale of properties and equipment | 1,918 | 3,322 |
Proceeds from Sale of Notes Receivable | 40,203 | |
Proceeds from divestiture | 43,493 | |
Increase (Decrease) in Restricted Cash | 1,249 | |
intercompany Transfer Investing Activities | (153,121) | (189,239) |
Net Cash Provided by (Used in) Investing Activities | (651,253) | (492,931) |
Proceeds from Lines of Credit | 629,000 | |
Repayment of revolving credit facility | (554,000) | |
Payments of Debt Issuance Costs | 4,086 | |
Treasury Stock, Value, Acquired, Cost Method | 4,700 | (5,325) |
Other | (842) | (906) |
Intercompany Transfers Financing Activities | 0 | 0 |
Net Cash Provided by (Used in) Financing Activities | 65,372 | (6,231) |
Net change in cash, cash equivalents, and restricted cash | (180,555) | (107,197) |
Cash, cash equivalents and restricted cash, beginning of period | 189,925 | 240,487 |
Cash, cash equivalents and restricted cash, end of period | 9,370 | 133,290 |
Reportable Legal Entities [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 28,687 | |
Payments to Explore and Develop Oil and Gas Properties | (213,132) | |
Payments for Capital Improvements | (1,252) | |
Payments to Acquire Businesses, Net of Cash Acquired | (5,279) | |
Proceeds from sale of properties and equipment | 0 | |
Proceeds from Sale of Notes Receivable | 0 | |
intercompany Transfer Investing Activities | 0 | |
Net Cash Provided by (Used in) Investing Activities | (209,105) | |
Treasury Stock, Value, Acquired, Cost Method | 0 | |
Other | (45) | |
Intercompany Transfers Financing Activities | 189,239 | |
Net Cash Provided by (Used in) Financing Activities | 189,194 | |
Net change in cash, cash equivalents, and restricted cash | 8,776 | |
Cash, cash equivalents and restricted cash, beginning of period | 3,613 | |
Cash, cash equivalents and restricted cash, end of period | 12,389 | |
Consolidation, Eliminations [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 0 | 0 |
Payments to Explore and Develop Oil and Gas Properties | 0 | 0 |
Payments for Capital Improvements | 0 | 0 |
Payments to Acquire Businesses, Net of Cash Acquired | 0 | 0 |
Proceeds from sale of properties and equipment | 0 | 0 |
Proceeds from Sale of Notes Receivable | 0 | |
Proceeds from divestiture | 0 | |
Purchases of short-term investments | 0 | |
Increase (Decrease) in Restricted Cash | 0 | 0 |
Proceeds from Sale of Short-term Investments | 0 | |
intercompany Transfer Investing Activities | 153,121 | 189,239 |
Net Cash Provided by (Used in) Investing Activities | 153,121 | 189,239 |
Proceeds from Lines of Credit | 0 | |
Repayment of revolving credit facility | 0 | |
Payments of Debt Issuance Costs | 0 | |
Treasury Stock, Value, Acquired, Cost Method | 0 | 0 |
Other | 0 | 0 |
Intercompany Transfers Financing Activities | (153,121) | (189,239) |
Net Cash Provided by (Used in) Financing Activities | (153,121) | (189,239) |
Net change in cash, cash equivalents, and restricted cash | 0 | 0 |
Cash, cash equivalents and restricted cash, beginning of period | 0 | 0 |
Cash, cash equivalents and restricted cash, end of period | 0 | 0 |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||
Net Cash Provided by (Used in) Operating Activities | 172,508 | |
Payments to Explore and Develop Oil and Gas Properties | (325,092) | |
Payments for Capital Improvements | (905) | |
Payments to Acquire Businesses, Net of Cash Acquired | (71) | |
Proceeds from sale of properties and equipment | 525 | |
Proceeds from divestiture | 0 | |
Purchases of short-term investments | 0 | |
Increase (Decrease) in Restricted Cash | 0 | 0 |
Proceeds from Sale of Short-term Investments | 0 | |
intercompany Transfer Investing Activities | 0 | |
Net Cash Provided by (Used in) Investing Activities | (325,543) | |
Proceeds from Lines of Credit | 0 | |
Repayment of revolving credit facility | 0 | |
Payments of Debt Issuance Costs | 0 | |
Treasury Stock, Value, Acquired, Cost Method | 0 | |
Other | (86) | |
Intercompany Transfers Financing Activities | 153,121 | |
Net Cash Provided by (Used in) Financing Activities | 153,035 | |
Net change in cash, cash equivalents, and restricted cash | 0 | |
Cash, cash equivalents and restricted cash, beginning of period | 0 | |
Cash, cash equivalents and restricted cash, end of period | $ 0 | |
Parent Company [Member] | Reportable Legal Entities [Member] | ||
Purchases of short-term investments | (49,890) | |
Increase (Decrease) in Restricted Cash | (9,250) | |
Proceeds from Sale of Short-term Investments | $ 49,890 |