Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 01, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | SILVERBOW RESOURCES, INC. | |
Entity Central Index Key | 351,817 | |
Document Type | 10-Q | |
Current Fiscal Year End Date | --12-31 | |
Document Period End Date | Mar. 31, 2018 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 11,652,637 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Current Assets: | ||
Cash and cash equivalents | $ 237 | $ 7,806 |
Accounts receivable, net | 21,133 | 27,263 |
Fair value of commodity derivatives | 2,704 | 5,148 |
Other current assets | 2,877 | 2,352 |
Total Current Assets | 26,951 | 42,569 |
Property and Equipment: | ||
Property and Equipment | 723,828 | 712,166 |
Less - Accumulated depreciation, depletion, and amortization | (229,901) | (216,769) |
Net Furniture, Fixtures and other equipment | 493,927 | 495,397 |
Other Long-Term Assets | 13,517 | 13,304 |
Total Assets | 534,395 | 551,270 |
Current Liabilities: | ||
Accounts payable and accrued liabilities | 32,289 | 44,437 |
Fair value of commodity derivatives | 7,666 | 5,075 |
Accrued capital costs | 20,445 | 10,883 |
Accrued interest | 2,298 | 2,106 |
Undistributed oil and gas revenues | 10,713 | 12,996 |
Total Current Liabilities | 73,411 | 75,497 |
Long-Term Debt | 245,371 | 265,325 |
Asset Retirement Obligation | 4,185 | 8,678 |
Other Long-Term Liabilities | 7,601 | 8,312 |
Stockholders' Equity: | ||
Preferred Stock, Value, Outstanding | 0 | 0 |
Common stock, $0.01 par value | 117 | 116 |
Additional paid-in capital | 281,303 | 279,111 |
Treasury stock held, at cost | (1,742) | (1,452) |
Retained earnings (Accumulated deficit) | (75,851) | (84,317) |
Total Stockholders' Equity (Deficit) | 203,827 | 193,458 |
Total Liabilities and Stockholders' Equity | $ 534,395 | $ 551,270 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Capitalized Costs, unproved property balance | $ 55,725 | $ 50,377 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 0 | 10,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares issued | 11,713,859 | 11,621,385 |
Common stock, shares outstanding | 11,652,637 | 11,570,621 |
Treasury stock shares held, at cost | 61,222 | 50,764 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenues: | ||
Oil and gas sales | $ 52,752 | $ 42,412 |
Costs and Expenses: | ||
General and administrative, net | 5,576 | 9,834 |
Depreciation, depletion, and amortization | 13,131 | 9,715 |
Accretion of asset retirement obligation | 159 | 564 |
Lease operating costs | 4,961 | 5,773 |
Transportation and gas processing | 5,025 | 4,385 |
Severance and other taxes | 3,031 | 1,618 |
Total Operating Expenses | 31,883 | 31,889 |
Operating Income (Loss) | 20,869 | 10,523 |
Net gain (loss) on commodity derivatives | (6,355) | 10,936 |
Interest expense, net | (5,890) | (3,607) |
Other income (expense), net | (158) | (142) |
Income (Loss) Before Income Taxes | 8,466 | 17,710 |
Provision (Benefit) for Income Taxes | 0 | 0 |
Net Income (Loss) | $ 8,466 | $ 17,710 |
Per Share Amounts- | ||
Earnings Per Share, Basic | $ 0.73 | $ 1.58 |
Earnings Per Share, Diluted | $ 0.72 | $ 1.57 |
Weighted Average Shares Outstanding - Basic | 11,602 | 11,232 |
Weighted Average Shares Outstanding - Diluted | 11,727 | 11,323 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings (Accumulated Deficit) |
Beginning Balance at Dec. 31, 2016 | $ 76,055 | $ 101 | $ 232,917 | $ (675) | $ (156,288) |
Purchase of treasury shares | (777) | 0 | 0 | (777) | 0 |
Issuance of common stock | 39,180 | 14 | 39,166 | 0 | 0 |
Issuance of restricted stock | 0 | 1 | (1) | 0 | 0 |
Amortization of share-based compensation | 7,029 | 0 | 7,029 | 0 | 0 |
Net Income (Loss) | 71,971 | 0 | 0 | 0 | 71,971 |
Ending Balance at Dec. 31, 2017 | 193,458 | 116 | 279,111 | (1,452) | (84,317) |
Shares issued from option exercise | 708 | 0 | 708 | 0 | 0 |
Purchase of treasury shares | (290) | 0 | 0 | 290 | 0 |
Issuance of restricted stock | 0 | 1 | (1) | 0 | 0 |
Amortization of share-based compensation | 1,485 | 0 | 1,485 | 0 | 0 |
Net Income (Loss) | 8,466 | 0 | 0 | 0 | 8,466 |
Ending Balance at Mar. 31, 2018 | $ 203,827 | $ 117 | $ 281,303 | $ (1,742) | $ (75,851) |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - shares | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Statement of Stockholders' Equity [Abstract] | ||
Stock Issued During Period, Shares, Employee Stock Ownership Plan | 0 | 0 |
Stock Issued During Period, Shares, Other | 29,199 | 0 |
Purchase of treasury stock (shares) | 10,458 | 28,279 |
Stock Issued During Period, Shares, Employee Stock Purchase Plans | 0 | 0 |
Issuance of restricted stock (shares) | 63,275 | 141,818 |
Issuance of common stock (shares) | 0 | 1,403,508 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Cash Flows from Operating Activities: | ||
Net Income (Loss) | $ 8,466 | $ 17,710 |
Adjustments to reconcile net income to net cash provided by operating activities - | ||
Depreciation, depletion, and amortization | 13,131 | 9,715 |
Accretion of asset retirement obligation | 159 | 564 |
Stock-based compensation expenses | 1,359 | 1,503 |
Loss (gain) on derivatives | 6,355 | (10,937) |
Cash settlements on derivatives | 977 | (811) |
Settlements of asset retirement obligations | (120) | (411) |
Debt issuance cost write-down | 0 | 450 |
Other Noncash Income (Expense) | 129 | (315) |
(Increase) decrease in accounts receivable and other current assets | 4,005 | (1,942) |
Increase (decrease) in accounts payable and accrued liabilities | (9,497) | (3,436) |
Increase (decrease) in accrued interest | 192 | (354) |
Net Cash Provided by (Used in) Operating Activities | 25,156 | 11,736 |
Cash Flows from Investing Activities: | ||
Additions to property and equipment | (33,753) | (25,417) |
Proceeds from the sale of property and equipment | 26,969 | 432 |
Payments on property sale obligations | (6,042) | 0 |
Transfer of company funds to restricted cash | 0 | (15) |
Transfer of company funds to restricted cash | 0 | 653 |
Net Cash Provided by (Used in) Investing Activities | (12,826) | (24,347) |
Cash Flows from Financing Activities: | ||
Proceeds from bank borrowings | 35,100 | 43,000 |
Payments of bank borrowings | (55,100) | (69,000) |
Net proceeds from issuances of common stock | 708 | 39,381 |
Purchase of treasury shares | (290) | (267) |
Payments of debt issuance costs | (317) | 0 |
Net Cash Provided by (Used in) Financing Activities | (19,899) | 13,114 |
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash | (7,569) | 503 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 457 | 1,000 |
Supplemental Disclosures of Cash Flows Information: | ||
Cash paid during period for interest, net of amounts capitalized | 5,170 | 2,959 |
Changes in capital accounts payable and capital accruals | 12,177 | 7,365 |
Increase (decrease) in other long-term liabilities for capital expenditures | $ (1,250) | $ 0 |
General Information
General Information | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General Information | (1) General Information SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is a growth oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested. The condensed consolidated financial statements included herein are unaudited and have been prepared by the Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 as filed with the Securities and Exchange Commission on March 1, 2018 though, as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh start accounting. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | (2) Summary of Significant Accounting Policies Basis of Presentation . The consolidated financial statements included herein have been prepared by SilverBow, and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On April 20, 2018, as part of our regularly scheduled borrowing base redetermination, we amended the terms of our Credit Facility and reaffirmed the borrowing base at $330 million . See Note 6 of these condensed consolidated financial statements for further details. There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, and • estimates in amounts due with respect to open state regulatory audits. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2018 and 2017 , such internal costs capitalized totaled $1.4 million and $0.9 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these condensed consolidated financial statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 664,742 $ 658,519 Unproved oil and gas properties 55,725 50,377 Furniture, fixtures, and other equipment 3,361 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (229,901 ) (216,769 ) Property and Equipment, Net $ 493,927 $ 495,397 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties-including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred. Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% , and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no write-down for each of the three months ended March 31, 2018 and 2017 . If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is likely that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. Revenue Recognition . The Company adopted the new revenue recognition standard for revenue from contracts from customers (ASC 606) effective January 1, 2018. See Note 3 in these condensed consolidated financial statements for further details. Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both March 31, 2018 and December 31, 2017 , we had an allowance for doubtful accounts of less than $0.1 million . The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets. At March 31, 2018 , our “Accounts receivable” balance included $17.0 million for oil and gas sales, $2.7 million due from joint interest owners, $1.1 million for severance tax credit receivables and $0.3 million for other receivables. At December 31, 2017 , our “Accounts receivable” balance included $20.1 million for oil and gas sales, $2.1 million due from joint interest owners, $2.1 million for severance tax credit receivables and $3.0 million for other receivables. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying condensed consolidated statements of operations. Our supervision fees are allocated to each well based on general and administrative costs incurred for well maintenance and support. The amount of supervision fees charged for each of the three months ended March 31, 2018 and 2017 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $1.1 million and $1.2 million for the three months ended March 31, 2018 and 2017 , respectively. Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company was in a net deferred tax asset position at both March 31, 2018 and March 31, 2017. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining carryover items and, accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with reported income before tax was fully offset by adjustments to the valuation allowance On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Act"). The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reduction of the U.S. federal corporate tax rate from 35% to 21% and a repeal of the alternative minimum tax regime, both effective January 1, 2018. Because of the Company’s net deferred tax asset and valuation allowance positions, these changes did not impact tax expense for the three months ended March 31, 2018. The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The Company’s deferred tax balances and offsetting valuation allowance should be considered provisional. The final application of the Act to the Company’s tax computations may result in further adjustments. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts. Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2018 December 31, 2017 Trade accounts payable $ 15,440 $ 20,884 Accrued operating expenses 2,964 3,490 Accrued compensation costs 1,956 5,334 Asset retirement obligations – current portion 467 2,109 Accrued non-income based taxes 4,058 3,898 Accrued corporate and legal fees 2,982 2,784 Other payables 4,422 5,938 Total accounts payable and accrued liabilities $ 32,289 $ 44,437 Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of each of March 31, 2018 and December 31, 2017 , these assets were approximately $0.2 million . These amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets. The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying condensed consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands): March 31, 2018 December 31, 2017 March 31, 2017 Cash and cash equivalents $ 237 $ 7,806 $ 168 Long-term restricted cash (1) 220 220 832 Total cash, cash equivalents and restricted cash $ 457 $ 8,026 $ 1,000 (1) Long-term restricted cash is included in “ Other Long-Term Assets ” on the accompanying condensed consolidated balance sheets. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets. For the three months ended March 31, 2018 , 10,458 treasury shares were purchased to satisfy withholding tax obligations arising upon the vesting of restricted shares. Fresh Start Accounting. Upon emergence from bankruptcy on April 22, 2016, the Company adopted Fresh Start Accounting. As a result of the application of fresh start accounting, as well as the effects of the implementation of the joint plan of reorganization (the “Plan”), the Consolidated Financial Statements on or after April 22, 2016 are not comparable with the Consolidated Financial Statements prior to that date. New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Updated (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. At December 31, 2017 the Company’s total lease commitments were approximately $6.2 million . There have been no material changes to our previously disclosed lease commitment amounts. Of this total, $2.0 million is related to our corporate office sub-lease which has a remaining term of 3.4 years. The remaining commitments are generally for equipment and vehicle leases, most of which are expiring during 2018. The Company did not enter into any significant additional lease obligations during the first three months of 2018 and is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing versus purchase for operating equipment. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted. In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018 with early adoption permitted. The Company has adopted this guidance as of January 1, 2018 and will apply it to any subsequent transactions. |
Revenue Recognition Revenue Rec
Revenue Recognition Revenue Recognition (Notes) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue Recognition [Abstract] | |
Revenue Recognition | (3) Revenue Recognition Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC Topic 606 supersedes previous revenue recognition requirements in ASC Topic 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. We have modified our processes and controls to ensure our reported oil and gas sales revenue is determined in accordance with this standard. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption. Virtually all of our revenue reported as oil and gas sales in our condensed consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606. Revenue from Contracts with Customers Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below: Sales Contracts for Unprocessed Gas We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements) we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take title and control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense. Contracts for Processed Gas and NGLs NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products. Where our raw gas contains commercially recoverable NGL components, we enter into agreements with mid-stream gas processors under which the processor takes delivery at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate. We either take delivery of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor the sales price is determined using monthly index prices. When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product. Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense. Contracts for Oil sales Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points. Contract balances Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the condensed consolidated balance sheets. See Note 2 above. Settlements for performance obligations We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals. Adjustments to prior period estimates were not material for the periods presented in our condensed consolidated statements of operations. Transaction price allocated to remaining performance obligations Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues. Oil and Gas sales by product The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended March 31, 2018 and 2017 (in thousands): Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Oil, natural gas and NGLs sales: Oil $ 11,439 $ 7,201 Natural gas 35,767 31,063 NGLs 5,560 4,148 Other (14 ) — Total $ 52,752 $ 42,412 |
Share-Based Compensation
Share-Based Compensation | 3 Months Ended |
Mar. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation | (4) Share-Based Compensation Share-Based Compensation Plans Upon the Company's emergence from bankruptcy on April 22, 2016, the Company's previous share-based compensation plans were canceled and the new 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan the outstanding restricted stock awards and restricted stock unit awards for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled. For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting. The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.4 million and $1.5 million for the three months ended March 31, 2018 and 2017 , respectively. Capitalized share-based compensation was $0.1 million and less than $0.1 million for the three months ended March 31, 2018 and 2017 , respectively. We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. Stock Option Awards The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards. At March 31, 2018 , we had $4.4 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2018 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 508,730 $ 26.82 Options granted — $ — Options forfeited (16,968 ) $ 26.96 Options expired (8,356 ) $ 26.96 Options exercised (29,199 ) $ 24.27 Options outstanding, end of period 454,207 $ 26.98 Options exercisable, end of period 136,938 $ 25.93 O ur outstanding stock option awards at March 31, 2018 had $1.3 million of aggregate intrinsic value. At March 31, 2018 , the weighted average remaining contract life of stock option awards outstanding was 6.9 years and exercisable was 4.0 years. The total intrinsic value of stock option awards exercisable for the three months ended March 31, 2018 was $0.5 million . Restricted Stock Units The 2016 equity incentive compensation plan allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years ). As of March 31, 2018 , we had unrecognized compensation expense of $8.0 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.7 years. The following table provides information regarding restricted stock unit award activity for the three months ended March 31, 2018 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 346,740 $ 26.99 Restricted stock units granted 78,300 $ 27.80 Restricted stock units forfeited (12,280 ) $ 26.91 Restricted stock units vested (62,577 ) $ 25.58 Restricted stock units outstanding, end of period 350,183 $ 27.43 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 performance-based stock units for which the number of shares earned is based on the Total Shareholder Return ("TSR") of the Company's common stock relative to the TSR of its selected peers ("Peer Group") during the performance period from January 1, 2018 to December 31, 2020 ("Performance Period"). The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% as a percentage of stock price with a remaining performance period of 2.9 years. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff vesting period of 3.0 years . As of March 31, 2018 , we had unrecognized compensation expense of $1.2 million related to our performance-based stock units, which is expected to be recognized over a period of 3.0 years . No shares vested during the three months ended March 31, 2018 . |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | (5) Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2018 and 2017 and are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 8,466 11,602 $ 0.73 $ 17,710 11,232 $ 1.58 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 18 76 Stock Option Awards 107 15 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 8,466 11,727 $ 0.72 $ 17,710 11,323 $ 1.57 Approximately 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for each of the three months ended March 31, 2018 and 2017 because these stock options were antidilutive. Approximately 0.1 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2017 because they were antidilutive. There were no antidilutive shares of restricted stock units for the three months ended March 31, 2018 and less than 0.1 million antidilutive shares of performance-based restricted stock units in such period. Approximately 4.3 million warrants to purchase common stock were not included in the computation of Diluted EPS for the three months ended March 31, 2018 and 2017 , respectively, because these warrants were antidilutive. |
Long-Term Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | (6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): March 31, 2018 December 31, 2017 Credit Facility Borrowings (1) $ 53,000 $ 73,000 Second Lien Notes due 2024 200,000 200,000 253,000 273,000 Unamortized discount on Second Lien Notes due 2024 (1,941 ) (1,992 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (2) (5,688 ) (5,683 ) Long-Term Debt, net $ 245,371 $ 265,325 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2018 and December 31, 2017 , we had $5.2 million and $5.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings. (2) During the first three months of 2018 , the Company capitalized an additional $0.3 million in debt issuance costs on the Second Lien Notes due 2024. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $53.0 million and $73.0 million as of March 31, 2018 and December 31, 2017 , respectively. On April 19, 2017 the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended, including by the Third Amendment dated April 20, 2018 (the “Third Amendment to Credit Agreement”) to the First Amended and Restated Senior Secured Credit Agreement (as amended, the “Credit Agreement” and such facility, the “Credit Facility”). The Third Amendment to Credit Agreement reaffirmed the borrowing base at $330 million , decreased the applicable margin used to calculate the interest rate under the Credit Agreement by 50 basis points and carved out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Credit Agreement. The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million . The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their discretion in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million , which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). As of April 20, 2018, the applicable margin ranges from 1.25% to 2.25% for ABR Loans and 2.25% to 3.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rates are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiaries. The Credit Agreement contains the following financial covenants: • a ratio of total debt to EBITDA, as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 4.0 to 1.0 as of the last day of each fiscal quarter; and • a current ratio, as defined in the Credit Agreement and which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter. As of March 31, 2018 , the Company was in compliance with all financial covenants under the Credit Agreement. Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, totaled $5.9 million and $3.6 million for the three months ended March 31, 2018 and 2017 , respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million and less than $0.1 million for the three months ended March 31, 2018 and 2017 , respectively. We capitalized interest on our unproved properties in the amount $0.4 million and $0.2 million for the three months ended March 31, 2018 and 2017 , respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a note purchase agreement for Senior Secured Second Lien Notes (the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of $200 million , with a $2.0 million discount, for net proceeds of $198.0 million . The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100 million . The Second Lien matures on December 15, 2024. On April 20, 2018 the Company entered into a First Amendment (the “First Amendment to the Second Lien”) which carves out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Note Purchase Agreement. Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5% ; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Second Lien. To the extent that a payment, insolvency or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the twenty-four month anniversary of the issuance of the Second Lien, discounted at a rate equal to the Treasury Rate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and certain of its subsidiaries, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 of proved reserves of the Company and its subsidiaries and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the Administrative Agent of the Credit Facility. The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiaries and in the denominator the total net indebtedness of the Company and its restricted subsidiaries, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio Requirement”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the purchase agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of March 31, 2018 , the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien Facility to be immediately due and payable. As of March 31, 2018 , total net amounts recorded for the Second Lien Notes were $192.4 million , net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.7 million for the three months ended March 31, 2018 . Debt Issuance Costs . Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. |
Acquisitions and Dispositions A
Acquisitions and Dispositions Acquisitions and Dispostions | 3 Months Ended |
Mar. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Dispositions | (7) Acquisitions and Dispositions On March 1, 2018, the Company closed the sale of certain wells in its AWP Olmos field for proceeds, net of selling expenses, of $27.0 million . The buyer assumed approximately $6.3 million in asset retirement obligations. No gain or loss was recorded on the sale of this property. Effective December 22, 2017, the Company closed a Purchase and Sale contract to sell the Company's wellbores and facilities in Bay De Chene and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Of the $16.3 million original obligation, $6.0 million was paid during the three months ended March 31, 2018 . Additionally, we reclassified $1.3 million in other long-term liabilities related to this sale to current liabilities. The remaining obligation under this contract is $10.2 million and is carried in the accompanying condensed consolidated balance sheet as of March 31, 2018 . This balance is made up of $6.4 million of current liability, which is included in “Accrued capital costs”, and $3.8 million which is included in “Other Long-Term Liabilities”. There were no acquisitions or dispositions of developed properties during the three months ended March 31, 2017 . |
Price-Risk Management Price-Ris
Price-Risk Management Price-Risk Management (Notes) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price-Risk Management Activities | (8) Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain (loss) on commodity derivatives" on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended March 31, 2018 and 2017 , the Company recorded losses of $6.4 million and gains of $10.9 million , respectively, on its commodity derivatives. The Company received net cash payments of $1.0 million and made net cash payments of $0.8 million for settled derivative contracts during the three months ended March 31, 2018 and 2017 , respectively. At March 31, 2018 and December 31, 2017 , we had $0.6 million and $2.2 million , respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in April 2018 and January 2018, respectively. At March 31, 2018 and December 31, 2017 , we also had $0.9 million and $0.4 million , respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in "Accounts payable and accrued liabilities" and were subsequently paid in April 2018 and January 2018, respectively. The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. At March 31, 2018 , there was $2.7 million and $3.1 million in current and long-term unsettled derivative assets and $7.7 million and $3.5 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2017 , there was $5.1 million and $2.6 million in current and long-term unsettled derivative assets and $5.1 million and $2.8 million in current and long-term unsettled derivative liabilities, respectively. The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a $5.4 million net fair value liability at March 31, 2018 and a $0.1 million net fair value liability at December 31, 2017 . For further discussion, related to the fair value of the Company's derivatives, refer to Note 9 of these condensed consolidated financial statements. The following tables summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of March 31, 2018 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 140,400 $ 52.57 3Q18 130,400 $ 52.40 4Q18 122,800 $ 52.23 2019 Contracts 1Q19 107,700 $ 52.77 2Q19 103,200 $ 52.72 3Q19 99,000 $ 52.79 4Q19 95,000 $ 52.73 2020 Contracts 1Q20 81,300 $ 52.42 2Q20 77,850 $ 52.38 3Q20 74,700 $ 52.34 4Q20 72,000 $ 52.29 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price 2018 Contracts 2Q18 5,868,000 $ 2.87 3Q18 9,834,000 $ 2.88 4Q18 11,241,000 $ 2.96 2019 Contracts 1Q19 7,516,000 $ 3.08 2Q19 6,060,000 $ 2.83 3Q19 5,550,000 $ 2.84 4Q19 5,966,000 $ 2.84 2020 Contracts 1Q20 5,370,000 $ 2.83 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 118,200 $ 24.78 3Q18 112,200 $ 24.78 4Q18 148,200 $ 24.78 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2018 Contracts 2Q18 5,765,000 $ (0.040 ) 3Q18 9,460,000 $ (0.020 ) 4Q18 10,550,000 $ (0.080 ) 2019 Contracts 1Q19 1,200,000 $ (0.100 ) 2Q19 1,205,000 $ 0.020 3Q19 1,210,000 $ 0.020 4Q19 1,210,000 $ (0.050 ) Oil Basis Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 80,000 $ 4.13 3Q18 120,000 $ 4.13 4Q18 120,000 $ 4.13 |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | (9) Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, bank borrowings, and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of March 31, 2018 and December 31, 2017 and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant March 31, 2018 Assets Natural Gas Derivatives $ 5.1 $ — $ 5.1 $ — Natural Gas Basis Derivatives $ 0.2 $ — $ 0.2 $ — NGL Derivatives $ 0.2 $ — $ 0.2 $ — Oil Basis Derivatives $ 0.3 $ — $ 0.3 $ — Liabilities Natural Gas Derivatives $ 1.4 $ — $ 1.4 $ — Natural Gas Basis Derivatives $ 2.0 $ — $ 2.0 $ — Oil Derivatives $ 7.4 $ — $ 7.4 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.3 $ — $ 0.3 $ — December 31, 2017 Assets Natural Gas Derivatives $ 7.2 $ — $ 7.2 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — NGL Derivatives $ 0.1 $ — $ 0.1 $ — Liabilities Natural Gas Derivatives $ 1.3 $ — $ 1.3 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Derivatives $ 5.2 $ — $ 5.2 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.9 $ — $ 0.9 $ — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Other current assets”, "Other long-term assets", "Accounts payable and accrued liabilities" and "Other long-term liabilities", respectively. |
Asset Retirement Obligations As
Asset Retirement Obligations Asset Retirement Obligations (Notes) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | (10) Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2017 and the three months ended March 31, 2018 (in thousands): Asset Retirement Obligations as of December 31, 2016 $ 32,256 Accretion expense 2,322 Liabilities incurred for new wells and facilities construction 253 Reductions due to sold wells and facilities (21,466 ) Reductions due to plugged wells and facilities (2,366 ) Revisions in estimates (212 ) Asset Retirement Obligations as of December 31, 2017 $ 10,787 Accretion expense 159 Liabilities incurred for new wells and facilities construction 7 Reductions due to sold wells and facilities (6,265 ) Reductions due to plugged wells and facilities (121 ) Revisions in estimates 85 Asset Retirement Obligations as of March 31, 2018 $ 4,652 At March 31, 2018 and December 31, 2017 , approximately $0.5 million and $2.1 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets. |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | (11) Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. |
Summary of Significant Accoun19
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. |
Use of Estimates | Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, and • estimates in amounts due with respect to open state regulatory audits. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. |
Property and Equipment | Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2018 and 2017 , such internal costs capitalized totaled $1.4 million and $0.9 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these condensed consolidated financial statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 664,742 $ 658,519 Unproved oil and gas properties 55,725 50,377 Furniture, fixtures, and other equipment 3,361 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (229,901 ) (216,769 ) Property and Equipment, Net $ 493,927 $ 495,397 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties-including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred. Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. |
Full-Cost Ceiling Test | Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% , and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. |
Accounts Receivable, Net | Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both March 31, 2018 and December 31, 2017 , we had an allowance for doubtful accounts of less than $0.1 million . The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets. |
Supervision Fees | Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying condensed consolidated statements of operations. Our supervision fees are allocated to each well based on general and administrative costs incurred for well maintenance and support. |
Income Taxes | Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company was in a net deferred tax asset position at both March 31, 2018 and March 31, 2017. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining carryover items and, accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with reported income before tax was fully offset by adjustments to the valuation allowance On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Act"). The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reduction of the U.S. federal corporate tax rate from 35% to 21% and a repeal of the alternative minimum tax regime, both effective January 1, 2018. Because of the Company’s net deferred tax asset and valuation allowance positions, these changes did not impact tax expense for the three months ended March 31, 2018. The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The Company’s deferred tax balances and offsetting valuation allowance should be considered provisional. The final application of the Act to the Company’s tax computations may result in further adjustments. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts. |
Accounts Payable and Accrued Liabilities | Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2018 December 31, 2017 Trade accounts payable $ 15,440 $ 20,884 Accrued operating expenses 2,964 3,490 Accrued compensation costs 1,956 5,334 Asset retirement obligations – current portion 467 2,109 Accrued non-income based taxes 4,058 3,898 Accrued corporate and legal fees 2,982 2,784 Other payables 4,422 5,938 Total accounts payable and accrued liabilities $ 32,289 $ 44,437 |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of each of March 31, 2018 and December 31, 2017 , these assets were approximately $0.2 million . These amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets. |
Treasury Stock | Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets. |
New Accounting Pronouncements | New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Updated (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. At December 31, 2017 the Company’s total lease commitments were approximately $6.2 million . There have been no material changes to our previously disclosed lease commitment amounts. Of this total, $2.0 million is related to our corporate office sub-lease which has a remaining term of 3.4 years. The remaining commitments are generally for equipment and vehicle leases, most of which are expiring during 2018. The Company did not enter into any significant additional lease obligations during the first three months of 2018 and is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing versus purchase for operating equipment. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted. In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018 with early adoption permitted. The Company has adopted this guidance as of January 1, 2018 and will apply it to any subsequent transactions. |
Revenue Recognition Revenue R20
Revenue Recognition Revenue Recognition (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue Recognition [Abstract] | |
Revenue Recognition, Policy | Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC Topic 606 supersedes previous revenue recognition requirements in ASC Topic 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. We have modified our processes and controls to ensure our reported oil and gas sales revenue is determined in accordance with this standard. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption. Virtually all of our revenue reported as oil and gas sales in our condensed consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606. Revenue from Contracts with Customers Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below: Sales Contracts for Unprocessed Gas We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements) we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take title and control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense. Contracts for Processed Gas and NGLs NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products. Where our raw gas contains commercially recoverable NGL components, we enter into agreements with mid-stream gas processors under which the processor takes delivery at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate. We either take delivery of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor the sales price is determined using monthly index prices. When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product. Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense. Contracts for Oil sales Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points. Contract balances Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the condensed consolidated balance sheets. See Note 2 above. Settlements for performance obligations We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals. Adjustments to prior period estimates were not material for the periods presented in our condensed consolidated statements of operations. Transaction price allocated to remaining performance obligations Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues. |
Share-Based Compensation Share-
Share-Based Compensation Share-Based Compensation (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-based Compensation, Option and Incentive Plans Policy | Share-Based Compensation Share-Based Compensation Plans Upon the Company's emergence from bankruptcy on April 22, 2016, the Company's previous share-based compensation plans were canceled and the new 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan the outstanding restricted stock awards and restricted stock unit awards for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled. For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting. |
Earnings Per Share Earnings Per
Earnings Per Share Earnings Per Share (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Share, Policy | Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2018 and 2017 and are discussed below. |
Long-Term Debt Long-Term Debt (
Long-Term Debt Long-Term Debt (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt Issuance Costs, Policy | Debt Issuance Costs . Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. |
Price-Risk Management Price-R24
Price-Risk Management Price-Risk Management (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price-Risk Management Activities, Policy | Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain (loss) on commodity derivatives" on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of commodity price swaps and collars as well as basis swaps. |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Disclosures (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments, Policy | Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, bank borrowings, and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. |
Asset Retirement Obligations 26
Asset Retirement Obligations Asset Retirement Obligations (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. |
Commitments and Contingencies27
Commitments and Contingencies Commitments and Contingencies (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies, Policy | Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Property and Equipment | The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 664,742 $ 658,519 Unproved oil and gas properties 55,725 50,377 Furniture, fixtures, and other equipment 3,361 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (229,901 ) (216,769 ) Property and Equipment, Net $ 493,927 $ 495,397 |
Accounts Payable and Accrued Liabilities | The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2018 December 31, 2017 Trade accounts payable $ 15,440 $ 20,884 Accrued operating expenses 2,964 3,490 Accrued compensation costs 1,956 5,334 Asset retirement obligations – current portion 467 2,109 Accrued non-income based taxes 4,058 3,898 Accrued corporate and legal fees 2,982 2,784 Other payables 4,422 5,938 Total accounts payable and accrued liabilities $ 32,289 $ 44,437 |
Cash, Cash Equivalents and Restricted Cash | The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying condensed consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands): March 31, 2018 December 31, 2017 March 31, 2017 Cash and cash equivalents $ 237 $ 7,806 $ 168 Long-term restricted cash (1) 220 220 832 Total cash, cash equivalents and restricted cash $ 457 $ 8,026 $ 1,000 (1) Long-term restricted cash is included in “ Other Long-Term Assets ” on the accompanying condensed consolidated balance sheets. |
Revenue Recognition Revenue R29
Revenue Recognition Revenue Recognition (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue Recognition [Abstract] | |
Oil and gas sales, by product [Table Text Block] | The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended March 31, 2018 and 2017 (in thousands): Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Oil, natural gas and NGLs sales: Oil $ 11,439 $ 7,201 Natural gas 35,767 31,063 NGLs 5,560 4,148 Other (14 ) — Total $ 52,752 $ 42,412 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock option activity | The following table provides information regarding stock option award activity for the three months ended March 31, 2018 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 508,730 $ 26.82 Options granted — $ — Options forfeited (16,968 ) $ 26.96 Options expired (8,356 ) $ 26.96 Options exercised (29,199 ) $ 24.27 Options outstanding, end of period 454,207 $ 26.98 Options exercisable, end of period 136,938 $ 25.93 |
Restricted stock activity | The following table provides information regarding restricted stock unit award activity for the three months ended March 31, 2018 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 346,740 $ 26.99 Restricted stock units granted 78,300 $ 27.80 Restricted stock units forfeited (12,280 ) $ 26.91 Restricted stock units vested (62,577 ) $ 25.58 Restricted stock units outstanding, end of period 350,183 $ 27.43 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS | The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 8,466 11,602 $ 0.73 $ 17,710 11,232 $ 1.58 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 18 76 Stock Option Awards 107 15 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 8,466 11,727 $ 0.72 $ 17,710 11,323 $ 1.57 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | The Company's long-term debt consisted of the following (in thousands): March 31, 2018 December 31, 2017 Credit Facility Borrowings (1) $ 53,000 $ 73,000 Second Lien Notes due 2024 200,000 200,000 253,000 273,000 Unamortized discount on Second Lien Notes due 2024 (1,941 ) (1,992 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (2) (5,688 ) (5,683 ) Long-Term Debt, net $ 245,371 $ 265,325 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2018 and December 31, 2017 , we had $5.2 million and $5.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings. (2) During the first three months of 2018 , the Company capitalized an additional $0.3 million in debt issuance costs on the Second Lien Notes due 2024. |
Price-Risk Management Price-R33
Price-Risk Management Price-Risk Management (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments [Table Text Block] | The following tables summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of March 31, 2018 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 140,400 $ 52.57 3Q18 130,400 $ 52.40 4Q18 122,800 $ 52.23 2019 Contracts 1Q19 107,700 $ 52.77 2Q19 103,200 $ 52.72 3Q19 99,000 $ 52.79 4Q19 95,000 $ 52.73 2020 Contracts 1Q20 81,300 $ 52.42 2Q20 77,850 $ 52.38 3Q20 74,700 $ 52.34 4Q20 72,000 $ 52.29 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price 2018 Contracts 2Q18 5,868,000 $ 2.87 3Q18 9,834,000 $ 2.88 4Q18 11,241,000 $ 2.96 2019 Contracts 1Q19 7,516,000 $ 3.08 2Q19 6,060,000 $ 2.83 3Q19 5,550,000 $ 2.84 4Q19 5,966,000 $ 2.84 2020 Contracts 1Q20 5,370,000 $ 2.83 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 118,200 $ 24.78 3Q18 112,200 $ 24.78 4Q18 148,200 $ 24.78 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2018 Contracts 2Q18 5,765,000 $ (0.040 ) 3Q18 9,460,000 $ (0.020 ) 4Q18 10,550,000 $ (0.080 ) 2019 Contracts 1Q19 1,200,000 $ (0.100 ) 2Q19 1,205,000 $ 0.020 3Q19 1,210,000 $ 0.020 4Q19 1,210,000 $ (0.050 ) Oil Basis Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 2Q18 80,000 $ 4.13 3Q18 120,000 $ 4.13 4Q18 120,000 $ 4.13 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of March 31, 2018 and December 31, 2017 and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant March 31, 2018 Assets Natural Gas Derivatives $ 5.1 $ — $ 5.1 $ — Natural Gas Basis Derivatives $ 0.2 $ — $ 0.2 $ — NGL Derivatives $ 0.2 $ — $ 0.2 $ — Oil Basis Derivatives $ 0.3 $ — $ 0.3 $ — Liabilities Natural Gas Derivatives $ 1.4 $ — $ 1.4 $ — Natural Gas Basis Derivatives $ 2.0 $ — $ 2.0 $ — Oil Derivatives $ 7.4 $ — $ 7.4 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.3 $ — $ 0.3 $ — December 31, 2017 Assets Natural Gas Derivatives $ 7.2 $ — $ 7.2 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — NGL Derivatives $ 0.1 $ — $ 0.1 $ — Liabilities Natural Gas Derivatives $ 1.3 $ — $ 1.3 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Derivatives $ 5.2 $ — $ 5.2 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.9 $ — $ 0.9 $ — |
Asset Retirement Obligations 35
Asset Retirement Obligations Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Roll-forward of our asset retirement obligations | The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2017 and the three months ended March 31, 2018 (in thousands): Asset Retirement Obligations as of December 31, 2016 $ 32,256 Accretion expense 2,322 Liabilities incurred for new wells and facilities construction 253 Reductions due to sold wells and facilities (21,466 ) Reductions due to plugged wells and facilities (2,366 ) Revisions in estimates (212 ) Asset Retirement Obligations as of December 31, 2017 $ 10,787 Accretion expense 159 Liabilities incurred for new wells and facilities construction 7 Reductions due to sold wells and facilities (6,265 ) Reductions due to plugged wells and facilities (121 ) Revisions in estimates 85 Asset Retirement Obligations as of March 31, 2018 $ 4,652 |
Summary of Significant Accoun36
Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Property and Equipment | ||||
Proved oil and gas properties | $ 664,742 | $ 658,519 | ||
Unproved oil and gas properties | 55,725 | 50,377 | ||
Furniture, fixtures, and other equipment | 3,361 | 3,270 | ||
Less - Accumulated depreciation, depletion, and amortization | (229,901) | (216,769) | ||
Net Furniture, Fixtures and other equipment | 493,927 | 495,397 | ||
Accounts Payable and Accrued Liabilities | ||||
Trade accounts payable | 15,440 | 20,884 | ||
Accrued operating expenses | 2,964 | 3,490 | ||
Accrued compensation costs | 1,956 | 5,334 | ||
Asset retirement obligation - current portion | 467 | 2,109 | ||
Accrued non-income based taxes | 4,058 | 3,898 | ||
Accrued corporate and legal fees | 2,982 | 2,784 | ||
Other payables | 4,422 | 5,938 | ||
Total accounts payable and accrued liabilities | 32,289 | 44,437 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract] | ||||
Cash and cash equivalents | 237 | 7,806 | $ 168 | |
Long-term restricted cash | 220 | 220 | 832 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 457 | $ 8,026 | $ 1,000 | $ 497 |
Summary of Significant Accoun37
Summary of Significant Accounting Policies (Details Textual) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2018USD ($)shares | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($)shares | Apr. 20, 2018USD ($) | Dec. 22, 2017 | Dec. 31, 2016USD ($) | |
Summary of Significant Accounting Policies | ||||||
Total capitalized internal costs | $ 1,400 | $ 900 | ||||
Proved oil and gas properties | 664,742 | $ 658,519 | ||||
Unproved oil and gas properties | 55,725 | 50,377 | ||||
Furniture, fixtures, and other equipment | 3,361 | 3,270 | ||||
Less - Accumulated depreciation, depletion, and amortization | (229,901) | (216,769) | ||||
Property and Equipment, Net | $ 493,927 | 495,397 | ||||
Discount rate for estimated future net revenues from proved properties | 10.00% | |||||
Write-down of oil and gas properties | $ 0 | 0 | ||||
Allowance for doubtful accounts receivable, current | 100 | 100 | ||||
Accounts receivable, gross | 17,000 | 20,100 | ||||
Accounts receivable related to joint interest owners | 2,700 | 2,100 | ||||
Severance tax receivable | 1,100 | 2,100 | ||||
Other receivables | $ 300 | 3,000 | ||||
Percentage of working interest in wells | 100.00% | |||||
Total amount of supervision fees charged to wells | $ 1,100 | 1,200 | ||||
Previous Federal Corporate Tax Rate | 0.35 | |||||
New Federal Corporate Tax Rate | 0.21 | |||||
Trade accounts payable | 15,440 | 20,884 | ||||
Accrued operating expenses | 2,964 | 3,490 | ||||
Accrued payroll costs | 1,956 | 5,334 | ||||
Asset retirement obligation - current portion | 467 | 2,109 | ||||
Accrued non-income based taxes | 4,058 | 3,898 | ||||
Accrued corporate and legal fees | 2,982 | 2,784 | ||||
Other payables | 4,422 | 5,938 | ||||
Accounts payable and accrued liabilities | 32,289 | 44,437 | ||||
Cash and cash equivalents | 237 | 168 | 7,806 | |||
Restricted Cash | 220 | 832 | 220 | |||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 457 | $ 1,000 | $ 8,026 | $ 497 | ||
Purchase of treasury stock (shares) | shares | 10,458 | 28,279 | ||||
Other Commitment | $ 6,200 | |||||
Lessee, Operating Lease, Term of Contract | 3 years 5 months | |||||
Minimum [Member] | ||||||
Summary of Significant Accounting Policies | ||||||
Estimated useful lives of property | 2 years | |||||
Maximum [Member] | ||||||
Summary of Significant Accounting Policies | ||||||
Estimated useful lives of property | 20 years | |||||
Subsequent Event [Member] | New Credit Facility [Member] | Line of Credit [Member] | ||||||
Summary of Significant Accounting Policies | ||||||
Line of Credit Facility, Current Borrowing Capacity | $ 330,000 | |||||
Office Lease [Member] | ||||||
Summary of Significant Accounting Policies | ||||||
Other Commitment | $ 2,000 |
Revenue Recognition Revenue R38
Revenue Recognition Revenue Recognition (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Disaggregation of Revenue [Line Items] | ||
Oil and gas sales | $ 52,752 | $ 42,412 |
Oil sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil, natural gas and NGL sales | 11,439 | 7,201 |
Natural gas sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil, natural gas and NGL sales | 35,767 | 31,063 |
NGL sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil, natural gas and NGL sales | 5,560 | 4,148 |
Other sales [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil, natural gas and NGL sales | $ (14) | $ 0 |
Share-Based Compensation (Detai
Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands | Feb. 20, 2018 | Sep. 30, 2017 | Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 |
Share-based Compensation (Details Textual) | |||||
Stock-based compensation expenses | $ 1,359 | $ 1,503 | |||
Share-based compensation (capitalized) | 100 | 100 | |||
Employee Stock Option [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock option award unrecognized compensation | 4,400 | ||||
Stock option award outstanding aggregate intrinsic value | 1,300 | ||||
Remaining contract life of outstanding stock options. | 6 years 11 months | ||||
Remaining contract life of exercisable stock option | 4 years | ||||
Stock option award exercisable aggregate intrinsic value | $ 500 | ||||
Stock Option Activity | |||||
Options outstanding, beginning of period, shares | 454,207 | 508,730 | |||
Options outstanding, beginning of period, weighted average price | $ 26.98 | $ 26.82 | |||
Options granted, shares | 0 | ||||
Options granted, weighted average price | $ 0 | ||||
Options forfeited, shares | (16,968) | ||||
Options forfeited, weighted average share price | $ 26.96 | ||||
Options canceled, shares | (8,356) | ||||
Options canceled, weighted average price | $ 26.96 | ||||
Options exercised, shares | (29,199) | ||||
Options exercised, weighted average price | $ 24.27 | ||||
Options exercisable, end of period, shares | 136,938 | ||||
Options exercisable, end of period, weighted average price | $ 25.93 | ||||
Restricted Stock Units (RSUs) [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock option award unrecognized compensation | $ 8,000 | ||||
Unrecognized compensation expense weighted-average period | 2 years 8 months | ||||
Restricted stock activity | |||||
Restricted shares outstanding, beginning of period, shares | 346,740 | ||||
Restricted shares outstanding, beginning of period, weighted average price | $ 26.99 | ||||
Restricted shares granted, shares | 78,300 | ||||
Restricted shares granted, weighted average price | $ 27.80 | ||||
Restricted shares forfeited, shares | (12,280) | ||||
Restricted shares forfeited, weighted average price | $ 26.91 | ||||
Restricted shares vested, shares | (62,577) | ||||
Restricted shares vested, weighted average price | $ 25.58 | ||||
Restricted shares outstanding, end of period, shares | 350,183 | ||||
Restricted shares outstanding, end of period, weighted average price | $ 27.43 | ||||
Performance-based stock unit [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock option award unrecognized compensation | $ 1,200 | ||||
Unrecognized compensation expense weighted-average period | 2 years 11 months | ||||
Restricted stock activity | |||||
Restricted shares granted, shares | 30,700 | ||||
Restricted shares granted, weighted average price | $ 41.66 | ||||
Restricted shares vested, shares | 0 | ||||
Percent of payout for performance based stock units | 150.61% | ||||
Minimum [Member] | Employee Stock Option [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock option award vesting period | 1 year | ||||
Minimum [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 1 year | ||||
Minimum [Member] | Performance-based stock unit [Member] | |||||
Restricted stock activity | |||||
Percent of payout for performance based stock units | 0.00% | ||||
Maximum Payout [Member] | Employee Stock Option [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock option award vesting period | 5 years | ||||
Maximum Payout [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 5 years | ||||
Maximum Payout [Member] | Performance-based stock unit [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 3 years | ||||
Restricted stock activity | |||||
Percent of payout for performance based stock units | 200.00% | ||||
General and Administrative Expense [Member] | |||||
Share-based Compensation (Details Textual) | |||||
Stock-based compensation expenses | $ 1,400 | $ 1,500 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Basic EPS: | |||
Net Income (Loss) | $ 8,466 | $ 17,710 | $ 71,971 |
Income, share amounts | 11,602 | 11,232 | |
Earnings Per Share, Basic | $ 0.73 | $ 1.58 | |
Dilutive Securities: | |||
Dilutive RSAs | 0 | 0 | |
Dilutive RSUs | 18 | 76 | |
Dilutive Stock Options | 107 | 15 | |
Diluted EPS: | |||
Net Income (Loss) Available to Common Stockholders, Diluted | $ 8,466 | $ 17,710 | |
Weighted Average Number of Shares Outstanding, Diluted | 11,727 | 11,323 | |
Earnings Per Share, Diluted | $ 0.72 | $ 1.57 | |
Stock Options [Member] | |||
Earnings Per Share (Textual) | |||
Antidilutive shares excluded from EPS, shares | 400 | 400 | |
Restricted Stock Units (RSUs) [Member] | |||
Earnings Per Share (Textual) | |||
Antidilutive shares excluded from EPS, shares | 0 | 100 | |
Performance Shares [Member] | |||
Earnings Per Share (Textual) | |||
Antidilutive shares excluded from EPS, shares | 100 | ||
Warrant [Member] | |||
Earnings Per Share (Textual) | |||
Antidilutive shares excluded from EPS, shares | 4,300 | 4,300 |
Long-Term Debt (Details)
Long-Term Debt (Details) | Dec. 15, 2017USD ($) | Apr. 19, 2017USD ($) | Mar. 31, 2018USD ($) | Mar. 31, 2017USD ($) | Apr. 20, 2018USD ($) | Dec. 31, 2017USD ($) |
Bank Borrowings | ||||||
Payments of Debt Issuance Costs | $ 317,000 | $ 0 | ||||
Long-term Debt, excluding current maturities | 245,371,000 | $ 265,325,000 | ||||
Gross interest expense including amortization of debt issuance costs | 5,890,000 | 3,607,000 | ||||
Second Lien [Abstract] | ||||||
Long-term debt, gross | 253,000,000 | 273,000,000 | ||||
New Credit Facility [Member] | ||||||
Bank Borrowings | ||||||
Debt Issuance Costs, Net | 5,200,000 | 5,500,000 | ||||
Second Lien Notes [Member] | ||||||
Bank Borrowings | ||||||
Debt Issuance Costs, Net | 5,688,000 | 5,683,000 | ||||
Long-term Debt, excluding current maturities | $ 198,000,000 | 200,000,000 | 200,000,000 | |||
Debt instrument escalating basis spread on base rate | 50 | |||||
Gross interest expense including amortization of debt issuance costs | 4,700,000 | |||||
Second Lien [Abstract] | ||||||
Long-term debt, gross | $ 200,000,000 | |||||
Debt Instrument, Unamortized Discount | (2,000,000) | (1,941,000) | (1,992,000) | |||
Additional notes issuable | $ 100,000,000 | |||||
Additional interest in the event of default | 0.020 | |||||
Make whole premium during years 1 and 2 | 0.02 | |||||
Make whole premium during year 3 | 0.02 | |||||
Make whole premium during year 4 | 0.01 | |||||
Second Lien, Required Security Interest on Proved Reserves | 85.00% | |||||
Second Lien, Required Security Interest on Oil and Gas Properties | 85.00% | |||||
Second Lien, Asset Coverage Ratio, Minimum | 1.3 | |||||
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum | 4.5 | |||||
Long-term debt, net | 192,400,000 | |||||
Second Lien Notes [Member] | Alternative Base Interest Rate [Member] | ||||||
Bank Borrowings | ||||||
Debt instrument escalating basis spread on base rate | 0.065 | |||||
Second Lien Notes [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||
Bank Borrowings | ||||||
Debt instrument escalating basis spread on base rate | 0.075 | |||||
Line of Credit [Member] | ||||||
Bank Borrowings | ||||||
Capitalized interest on our unproved properties | 400,000 | 200,000 | ||||
Line of Credit [Member] | New Credit Facility [Member] | ||||||
Bank Borrowings | ||||||
Long-term Debt, excluding current maturities | 53,000,000 | $ 73,000,000 | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 600,000,000 | |||||
Line of Credit, Letters of Credit Issuable | $ 25,000,000 | |||||
Commitment fee basis points for the credit facility | 0.50% | |||||
Line of Credit, Additional Interest Due to Payment Default | 2.00% | |||||
Line of Credit, Required Security Interest on Oil and Gas Properties | 85.00% | |||||
Line of Credit, Covenant, Debt to EBITDA Ratio, Minimum | 4 | |||||
Line of Credit, Covenant, Current Ratio, Minimum | 1 | |||||
Gross interest expense including amortization of debt issuance costs | 5,900,000 | 3,600,000 | ||||
Commitment fees included in interest expense, net | $ 300,000 | $ 100,000 | ||||
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Alternative Base Interest Rate [Member] | ||||||
Bank Borrowings | ||||||
Debt instrument escalating basis spread on base rate | 0.0125 | |||||
Debt Instrument Escalating Rates for Eurodollar Rate Loans | 0.0225 | |||||
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Alternative Base Interest Rate [Member] | ||||||
Bank Borrowings | ||||||
Debt instrument escalating basis spread on base rate | 0.0225 | |||||
Debt Instrument Escalating Rates for Eurodollar Rate Loans | 0.0325 | |||||
Subsequent Event [Member] | Line of Credit [Member] | New Credit Facility [Member] | ||||||
Bank Borrowings | ||||||
Line of Credit Facility, Current Borrowing Capacity | $ 330,000,000 | |||||
Decrease in applicable margin to calculate interest | $ 50 |
Acquisitions and Dispositions42
Acquisitions and Dispositions Acquisitions and Dispositions (Details) - USD ($) $ in Thousands | Jan. 24, 2018 | Mar. 31, 2018 | Mar. 31, 2017 | Dec. 22, 2017 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Payments for (Proceeds from) Other Investing Activities | $ 6,042 | $ 0 | ||
AWP Olmos Sale [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 27,000 | |||
Buyer's Assumption of ARO | $ 6,300 | |||
Bay De Chene [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Purchase and sale contract | $ 16,300 | |||
Long-term liability reclassified to current | 1,300 | |||
Cash to be released for purchase and sale contract | 10,200 | |||
Other Current Liabilities [Member] | Bay De Chene [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Purchase and sale contract | 6,400 | |||
Other Noncurrent Liabilities [Member] | Bay De Chene [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Purchase and sale contract | $ 3,800 |
Price-Risk Management Price-R43
Price-Risk Management Price-Risk Management (Details) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018USD ($)MMBTU$ / MMBTU$ / Boebbl | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Gain (Loss) on Price Risk Derivatives, Net | $ | $ (6,400) | $ 10,900 | |
Cash Received (Paid) On Settlements of Derivative Contracts | $ | 977 | $ (811) | |
Receivables for Settled Derivatives | $ | 600 | $ 2,200 | |
Payables for Settled Derivatives | $ | 900 | 400 | |
Derivative, Fair Value, Net | $ | (5,400) | (100) | |
Other Current Assets [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | $ | 2,700 | 5,100 | |
Other Noncurrent Assets [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | $ | 3,100 | 2,600 | |
Other Current Liabilities [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative Liability, Fair Value, Gross Liability | $ | 7,700 | 5,100 | |
Other Noncurrent Liabilities [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative Liability, Fair Value, Gross Liability | $ | $ 3,500 | $ 2,800 | |
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.57 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 140,400 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.40 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 130,400 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.23 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 122,800 | ||
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.77 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 107,700 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.72 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 103,200 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.79 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 99,000 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.73 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 95,000 | ||
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.42 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 81,300 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.38 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 77,850 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.34 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 74,700 | ||
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 52.29 | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 72,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.87 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 5,868,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.88 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 9,834,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.96 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 11,241,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 3.08 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 7,516,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.83 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 6,060,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.84 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 5,550,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.84 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 5,966,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.83 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 5,370,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.76 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 3,688,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.76 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 3,585,000 | ||
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2020 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 2.77 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 3,362,000 | ||
Swap [Member] | Natural Gas Liquid Derivative [Member] | Second Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 24.78 | ||
Future NGL Production Hedged in Bbls (Energy Item Type) | bbl | 118,200 | ||
Swap [Member] | Natural Gas Liquid Derivative [Member] | Third Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 24.78 | ||
Future NGL Production Hedged in Bbls (Energy Item Type) | bbl | 112,200 | ||
Swap [Member] | Natural Gas Liquid Derivative [Member] | Fourth Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Swap Type, Fixed Price | 24.78 | ||
Future NGL Production Hedged in Bbls (Energy Item Type) | bbl | 148,200 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (0.04) | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 5,765,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (0.02) | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 9,460,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (0.08) | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 10,550,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (0.10) | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 1,200,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | 0.02 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 1,205,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | 0.02 | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 1,210,000 | ||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2019 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (0.05) | ||
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU | 1,210,000 | ||
Basis Swap [Member] | Oil Basis Derivative [Member] | Second Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (4.13) | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 80,000 | ||
Basis Swap [Member] | Oil Basis Derivative [Member] | Third Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (4.13) | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 120,000 | ||
Basis Swap [Member] | Oil Basis Derivative [Member] | Fourth Quarter 2018 [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Derivative, Basis Swap Type, Fixed Price | (4.13) | ||
Portion of Future Oil and Gas Production Being Hedged | bbl | 120,000 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 5.1 | $ 7.2 |
Derivative Liability | 1.4 | 1.3 |
Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.2 | 0.3 |
Derivative Liability | 2 | 0.3 |
Natural Gas Liquid Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.2 | 0.1 |
Derivative Liability | 0.3 | 0.9 |
Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 7.4 | 5.2 |
Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.3 | |
Derivative Liability | 0.1 | 0.1 |
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquid Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 5.1 | 7.2 |
Derivative Liability | 1.4 | 1.3 |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.2 | 0.3 |
Derivative Liability | 2 | 0.3 |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquid Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.2 | 0.1 |
Derivative Liability | 0.3 | 0.9 |
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 7.4 | 5.2 |
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.3 | |
Derivative Liability | 0.1 | 0.1 |
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquid Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | |
Derivative Liability | $ 0 | $ 0 |
Asset Retirement Obligations 45
Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | ||||
Asset Retirement Obligation | $ 4,652 | $ 10,787 | $ 32,256 | |
Accretion expense | 159 | $ 564 | 2,322 | |
Liabilities incurred for new wells and facilities construction | 7 | 253 | ||
Reductions due to sold wells and facilities | (6,265) | (21,466) | ||
Reductions due to plugged wells and facilities | (121) | (2,366) | ||
Revisions in estimates | 85 | (212) | ||
Asset retirement obligation - current portion | $ 467 | $ 2,109 |