Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2017 | Nov. 06, 2017 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Entity Registrant Name | Contango Oil & Gas Company | |
Entity Central Index Key | 1,071,993 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 25,509,792 | |
Entity Current Reporting Status | Yes |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
CURRENT ASSETS: | ||
Cash and cash equivalents | ||
Accounts receivable, net | 11,757 | 16,727 |
Prepaid expenses | 1,786 | 1,787 |
Current derivative asset | 440 | |
Inventory | 540 | |
Total current assets | 13,983 | 19,054 |
Natural gas and oil properties, successful efforts method of accounting: | ||
Proved properties | 1,221,391 | 1,188,065 |
Unproved properties | 38,720 | 38,338 |
Other property and equipment | 1,272 | 1,265 |
Accumulated depreciation, depletion and amortization | (918,768) | (887,286) |
Total property, plant and equipment, net | 342,615 | 340,382 |
OTHER NON-CURRENT ASSETS: | ||
Investments in affiliates | 18,242 | 15,767 |
Other | 954 | 1,311 |
Total other non-current assets | 19,196 | 17,078 |
TOTAL ASSETS | 375,794 | 376,514 |
CURRENT LIABILITIES: | ||
Accounts payable and accrued liabilities | 45,401 | 55,135 |
Current derivative liability | 90 | 3,446 |
Current asset retirement obligations | 4,008 | 4,308 |
Total current liabilities | 49,499 | 62,889 |
NON-CURRENT LIABILITIES: | ||
Long-term debt | 79,226 | 54,354 |
Asset retirement obligations | 18,082 | 22,618 |
Other long term liabilities | 248 | 248 |
Total non-current liabilities | 97,556 | 77,220 |
Total liabilities | 147,055 | 140,109 |
COMMITMENTS AND CONTINGENCIES (NOTE 12) | ||
SHAREHOLDERS' EQUITY: | ||
Common stock, $0.04 par value, 50 million shares authorized, 30,887,073 shares issued and 25,544,705 shares outstanding at September 30, 2017, 30,557,987 shares issued and 25,238,600 shares outstanding at December 31, 2016 | 1,224 | 1,211 |
Additional paid-in capital | 300,986 | 296,439 |
Treasury shares at cost (5,342,368 shares at September 30, 2017 and 5,319,387 shares at December 31, 2016) | (128,482) | (128,321) |
Retained earnings | 55,011 | 67,076 |
Total shareholders' equity | 228,739 | 236,405 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ 375,794 | $ 376,514 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Sep. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.04 | $ 0.04 |
Common stock, shares authorized | 50,000,000 | 50,000,000 |
Common stock, shares issued | 30,887,073 | 30,557,987 |
Common stock, shares outstanding | 25,544,705 | 25,238,600 |
Treasury stock, shares | 5,342,368 | 5,319,387 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
REVENUES: | ||||
Oil and condensate sales | $ 6,109 | $ 4,946 | $ 18,134 | $ 17,164 |
Natural gas sales | 9,681 | 12,011 | 31,956 | 31,283 |
Natural gas liquids sales | 3,040 | 2,619 | 8,440 | 8,073 |
Total revenues | 18,830 | 19,576 | 58,530 | 56,520 |
EXPENSES: | ||||
Operating expenses | 7,041 | 8,158 | 20,203 | 22,782 |
Exploration expenses | 315 | 444 | 690 | 1,088 |
Depreciation, depletion and amortization | 11,193 | 15,166 | 35,678 | 49,586 |
Impairment and abandonment of oil and gas properties | 84 | 1,165 | 1,515 | 4,268 |
General and administrative expenses | 6,219 | 7,486 | 18,648 | 18,772 |
Total expenses | 24,852 | 32,419 | 76,734 | 96,496 |
OTHER INCOME (EXPENSE): | ||||
Gain from investment in affiliates, net of income taxes | 525 | 467 | 2,475 | 1,802 |
Gain (loss) from sale of assets | (184) | 11 | 2,336 | 11 |
Interest expense | (1,138) | (989) | (2,822) | (3,045) |
Gain (loss) on derivatives, net | (9) | 913 | 4,574 | 736 |
Other income (expense) | 7 | (27) | (303) | |
Total other income (expense) | (806) | 409 | 6,536 | (799) |
NET LOSS BEFORE INCOME TAXES | (6,828) | (12,434) | (11,668) | (40,775) |
Income tax provision | (88) | (51) | (397) | (410) |
NET LOSS | $ (6,916) | $ (12,485) | $ (12,065) | $ (41,185) |
NET LOSS PER SHARE: | ||||
Basic (in dollars per share) | $ (0.28) | $ (0.55) | $ (0.49) | $ (2.02) |
Diluted (in dollars per share) | $ (0.28) | $ (0.55) | $ (0.49) | $ (2.02) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | ||||
Basic (in shares) | 24,708 | 22,881 | 24,662 | 20,370 |
Diluted (in shares) | 24,708 | 22,881 | 24,662 | 20,370 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net loss | $ (12,065) | $ (41,185) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 35,678 | 49,586 |
Impairment of natural gas and oil properties | 1,400 | 4,137 |
Exploration recovery | (232) | (2) |
Gain on sale of assets | (2,336) | (11) |
Gain from investment in affiliates | (2,475) | (1,802) |
Stock-based compensation | 4,560 | 4,315 |
Unrealized loss (gain) on derivative instruments | (3,797) | 2,400 |
Changes in operating assets and liabilities: | ||
Decrease in accounts receivable & other receivables | 4,767 | 7,026 |
Decrease (increase) in prepaids | 1 | (282) |
Decrease in inventory | 123 | |
Decrease in accounts payable & advances from joint owners | (1,744) | (5,621) |
Increase in other accrued liabilities | 2,461 | 2,384 |
Decrease in income taxes receivable, net | 2,868 | |
Decrease in income taxes payable, net | (308) | (200) |
Other | 72 | (17) |
Net cash provided by operating activities | 26,105 | 23,596 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Natural gas and oil exploration and development expenditures | (51,937) | (19,849) |
Additions to furniture & equipment | (42) | |
Sale of furniture & equipment | 12 | 11 |
Sale of oil and gas properties | 1,151 | |
Net cash used in investing activities | (50,816) | (19,838) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under credit facility | 172,015 | 118,310 |
Repayments under credit facility | (147,143) | (171,293) |
Net proceeds from equity offering | 50,451 | |
Purchase of treasury stock | (161) | (230) |
Debt issuance costs | (996) | |
Net cash provided by (used in) financing activities | 24,711 | (3,758) |
NET CHANGE IN CASH AND CASH EQUIVALENTS | 0 | 0 |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | ||
CASH AND CASH EQUIVALENTS, END OF PERIOD |
Consolidated Statement Of Share
Consolidated Statement Of Shareholders Equity - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands | Common Stock [Member] | Additional Paid-In Capital [Member] | Treasury Stock [Member] | Retained Earnings [Member] | Total |
Balance at Dec. 31, 2016 | $ 1,211 | $ 296,439 | $ (128,321) | $ 67,076 | $ 236,405 |
Balance, shares at Dec. 31, 2016 | 25,238,600 | 25,238,600 | |||
Treasury shares at cost | (161) | $ (161) | |||
Treasury shares at cost, shares | (22,981) | ||||
Restricted shares activity | $ 13 | (13) | |||
Restricted shares activity, shares | 329,086 | ||||
Stock-based compensation | 4,560 | 4,560 | |||
Net income | (12,065) | (12,065) | |||
Balance at Sep. 30, 2017 | $ 1,224 | $ 300,986 | $ (128,482) | $ 55,011 | $ 228,739 |
Balance, shares at Sep. 30, 2017 | 25,544,705 | 25,544,705 |
Organization And Business
Organization And Business | 9 Months Ended |
Sep. 30, 2017 | |
Organization And Business [Abstract] | |
Organization And Business | 1. Organization and Business Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the Texas and Rocky Mountain regions of the United States. The following table lists the Company’s primary producing areas as of September 30, 2017: Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Pecos County, Texas Southern Delaware Basin (Wolfcamp) Texas Gulf Coast Conventional and unconventional formations Zavala and Dimmit counties, Texas Buda / Austin Chalk Weston County, Wyoming Muddy Sandstone Sublette County, Wyoming Jonah Field (1) (1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for the three and nine months ended September 30, 2017. In July 2016, the Company purchased approximately 12,100 gross operated undeveloped acres (5,000 net acres) in the Southern Delaware Basin in Pecos County, Texas, which it began drilling during the fourth quarter of 2016, and as of September 30, 2017, had increased its acreage to approximately 13,600 gross operated acres (6,800 net). The Company’s 2017 capital program has focused, and will continue to focus, on the development of the Company’s Southern Delaware Basin acreage. Additionally, the Company will continue to identify opportunities for cost efficiencies in all areas of its operations, maintain core leases and identify new resource potential opportunities internally and, where appropriate, through acquisition. The Company will continuously monitor the commodity price environment, including its stability and forecast, and, if warranted, make adjustments to its strategy as the year progresses. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2017 | |
Summary Of Significant Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | 2. Summary of Significant Accounting Policies The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2016 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report. Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2016 Form 10-K. The consolidated results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by our wholly owned subsidiary, Contaro Company (“Contaro”) is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results. Oil and Gas Properties - Successful Efforts Our application of the successful efforts method of accounting for our natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized no impairment of proved properties for the three and nine months ended September 30, 2017. No impairment of proved properties was recognized for the three months ended September 30, 2016, and the Company recognized approximately $0.7 million impairment of proved properties for the nine months ended September 30, 2016, substantially all of which was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized no impairment of unproved properties for the three months ended September 30, 2017 and $1.4 million in impairment expense related to the partial impairment of two unused offshore platforms for the nine months ended September 30, 2017. The Company recognized impairment expense of approximately $1.1 million and approximately $3.4 million for the three and nine months ended September 30, 2016, respectively, related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases, substantially all of which was related to unproved lease cost amortization of marginal, non-core properties in Fayette and Gonzales counties, Texas. Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, Performance Stock Units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three months ended September 30, 2017, the Company excluded 971,813 potentially dilutive securities, as they were antidilutive, and excluded 813,151 potentially dilutive securities for the nine months ended September 30, 2017, as they were antidilutive. For the three months ended September 30, 2016, the Company excluded 439,017 potentially dilutive securities, as they were antidilutive, and 382,867 potentially dilutive securities were excluded for the nine months ended September 30, 2016, as they were antidilutive. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. Finally, the Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Recent Accounting Pronouncements In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its initial review of all revenue contracts. The Company’s revenue contracts are normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | 3. Acquisitions and Dispositions In July 2016, the Company purchased one-half of the seller’s interest in approximately 12,100 gross undeveloped acres (approximately 5,000 net acres) in the Southern Delaware Basin of Texas for up to $25 million (the “Acquisition”). The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million to be paid in the form of carried well costs expected to be paid over the period of drilling and completion of the first six wells. Additionally, contingent upon success, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which would increase the total consideration paid by the Company to $25 million. As of September 30, 2017, the Company had paid all $10 million of the carried well costs and $0.7 million in spud bonuses. As of September 30, 2017, the Company had increased its acreage to approximately 13,600 gross operated acres (6,800 net). On December 30, 2016, all of the Company’s non-core Colorado assets were sold to an independent oil and gas company for an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The properties consisted of the Company’s approximately 16,000 gross (11,200 net) acres primarily in Adams and Weld counties, Colorado and associated producing vertical wells. Effective February 1, 2017, the Company sold to a third party all of its assets in the North Bob West area and its operated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. The Company recorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | 4. Fair Value Measurements Pursuant to Accounting Standards Codification 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2017. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Fair value information for financial assets and liabilities was as follows as of September 30, 2017 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 440 $ — $ 440 $ — Commodity price contracts - liabilities $ (90) $ — $ (90) $ — Derivatives listed above are recorded in “Current derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives. As of September 30, 2017, the Company's derivative contracts were with certain members of its credit facility lenders which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”) approximates carrying value because the facility interest rate approximates current market rates and is reset at least every six months. See Note 9 - "Long-Term Debt" for further information. Impairments Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Asset Retirement Obligations The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments [Abstract] | |
Derivative Instruments | 5. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of September 30, 2017, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costless collars”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract. It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts as they are secured under the RBC Credit Facility. See Note 9 - "Long-Term Debt" for further information regarding the RBC Credit Facility. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on derivatives, net" on the consolidated statements of operations. The following derivative instruments were in place at September 30, 2017 (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Oct 2017 Collar 200,000 MMBtu $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Oct 2017 Swap 70,000 MMBtu $ Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtu $ Oil Oct 2017 Swap 6,000 Bbls $ Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ Oil Oct 2017 - Dec 2017 Swap 9,000 Bbls $ Total net fair value of derivative instruments $ 350 (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2017 (in thousands): Gross Netting (1) Total Assets $ 440 $ — $ 440 Liabilities $ (90) $ — $ (90) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2016 (in thousands): Gross Netting (1) Total Assets $ — $ — $ — Liabilities $ (3,446) $ — $ (3,446) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Crude oil contracts $ 342 $ — $ 879 $ — Natural gas contracts 179 (619) (102) 3,136 Realized gain (loss) $ 521 $ (619) $ 777 $ 3,136 Crude oil contracts $ (661) $ — $ 156 $ — Natural gas contracts 131 1,532 3,641 (2,400) Unrealized gain (loss) $ (530) $ 1,532 $ 3,797 $ (2,400) Gain (loss) on derivatives, net $ (9) $ 913 $ 4,574 $ 736 In October 2017, the Company entered into the following additional financial derivative contracts with a member of its credit facility lenders: Commodity Period Derivative Volume/Month Price/Unit (1) Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtu $ 3.07 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtu $ 3.07 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtu $ 3.07 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and Argus Louisiana Light Sweet oil prices, as applicable. |
Stock-Based Compensation
Stock-Based Compensation | 9 Months Ended |
Sep. 30, 2017 | |
Stock-Based Compensation [Abstract] | |
Stock-Based Compensation | 6. Stock-Based Compensation The Company recognized approximately $4.6 million and $4.3 million in stock compensation expense during the nine months ended September 30, 2017 and 2016, respectively, for equity awards granted to its officers, employees and directors. As of September 30, 2017, an additional $6.2 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 2.1 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options. Restricted Stock During the nine months ended September 30, 2017, the Company granted 383,376 shares of restricted common stock, which vest over three years, to new and existing employees as part of their overall compensation package, and 74,325 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average intrinsic value of the restricted shares granted during the nine months ended September 30, 2017, was $7.55 with a total fair value of approximately $3.5 million after adjustment for an estimated weighted average forfeiture rate of 5.7%. During the nine months ended September 30, 2017, 128,615 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2017 was approximately $1.3 million. Approximately 1.6 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2017, assuming PSUs are settled at 100% of target. During the nine months ended September 30, 2016, the Company granted 40,876 immediately vested shares of restricted common stock. Of these, 38,943 shares were granted to employees and 1,933 shares were granted to directors, all of which were issued pursuant to the Company’s salary replacement program (the “Salary Replacement Program”) which temporarily deferred 10% of 2015 employee salaries and director fees. Additionally, the Company granted 197,306 shares of restricted common stock to employees as part of their overall compensation package, which vest over four years, and 49,460 shares of restricted common stock to directors pursuant to the Company’s Director Compensation Plan, which vest over one year. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2016, was $11.60 with a total fair value of approximately $3.3 million after adjustment for an estimated weighted average forfeiture rate of 3.5%. During the nine months ended September 30, 2016, 4,160 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2016 was approximately $130 thousand. Performance Stock Units During the nine months ended September 30, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2017, 94,063 PSUs were forfeited by former employees. No PSUs were issued or forfeited during the nine months ended September 30, 2016. PSUs represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the number of PSUs awarded contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. Stock Options Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 2017 and 2016, there was no excess tax benefit recognized. Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the nine months ended September 30, 2017 or 2016. During the nine months ended September 30, 2017, no stock options were exercised, while 17,072 stock options were forfeited by former employees. During the nine months ended September 30, 2016, no stock options were exercised and stock options for 1,657 shares of common stock were forfeited. |
Other Financial Information
Other Financial Information | 9 Months Ended |
Sep. 30, 2017 | |
Other Financial Information [Abstract] | |
Other Financial Information | 7. Other Financial Information The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): September 30, 2017 December 31, 2016 Accounts receivable: Trade receivables $ 7,262 $ 8,424 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 2,972 3,519 Income taxes receivable 92 91 Other receivables 335 3,395 Allowance for doubtful accounts (897) (695) Total accounts receivable $ 11,757 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 1,088 $ 1,086 Other 698 701 Total prepaid expenses and other $ 1,786 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 19,343 $ 16,920 Advances from partners 3,230 5,792 Accrued exploration and development 8,189 11,176 Accrued carried well costs — 7,155 Trade payables 5,433 5,406 Accrued LOE & workover expense 2,228 1,867 Accrued G&A and legal expense 3,997 5,016 Other accounts payable and accrued liabilities 2,981 1,803 Total accounts payable and accrued liabilities $ 45,401 $ 55,135 Included in the table below is supplemental information about certain cash and non-cash transactions during the nine months ended September 30, 2017 and 2016 (in thousands): Nine Months Ended September 30, 2017 2016 Cash payments: Interest payments $ 2,501 $ 2,935 Income tax payments (refunds) $ 708 $ (2,337) Non-cash investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures $ (10,142) $ 7,248 |
Investment In Exaro Energy III
Investment In Exaro Energy III LLC | 9 Months Ended |
Sep. 30, 2017 | |
Investment In Exaro Energy III LLC [Abstract] | |
Investment In Exaro Energy III LLC | 8. Investment in Exaro Energy III LLC The Company maintains an ownership interest in Exaro of approximately 37%. The following table (in thousands) presents condensed balance sheet data for Exaro as of September 30, 2017 and December 31, 2016. The balance sheet data was derived from Exaro’s balance sheet as of September 30, 2017 and December 31, 2016 and was not adjusted to represent the Company’s percentage of ownership interest in Exaro. The Company’s share in the equity of Exaro at September 30, 2017 was approximately $18.1 million. September 30, 2017 December 31, 2016 Current assets (1) $ 15,897 $ 25,296 Non-current assets: Net property and equipment 84,766 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 57 8 Total non-current assets 85,973 91,779 Total assets $ 101,870 $ 117,075 Current liabilities (2) $ 3,950 $ 65,694 Non-current liabilities: Long-term debt 44,356 — Other non-current liabilities 3,466 8,106 Total non-current liabilities 47,822 8,106 Members' equity 50,098 43,275 Total liabilities & members' equity $ 101,870 $ 117,075 (1) Approximately $13.6 million and $19.6 million of current assets as of September 30, 2017 and December 31, 2016, respectively, is cash. (1) Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced. The following table (in thousands) presents the condensed results of operations for Exaro for the three and nine months ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 2017 and 2016 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company’s share in Exaro’s results of operations recognized for the three months ended September 30, 2017 and 2016 was a gain of $0.5 million, net of no tax expense. The Company’s share in Exaro’s results of operations recognized for the nine months ended September 30, 2017 and 2016 was a gain of $2.5 million, net of no tax expense, and a gain of $1.8 million, net of no tax expense, respectively. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Production: Oil (thousand barrels) 24 30 77 98 Gas (million cubic feet) 2,216 2,659 6,797 8,083 Total (million cubic feet equivalent) 2,360 2,839 7,260 8,671 Oil and natural gas sales $ 7,483 $ 8,242 $ 24,499 $ 20,730 Gain (loss) on derivatives 318 1,011 3,720 (1,231) Other gain — — — 10,441 Less: Lease operating expenses 2,928 3,969 10,914 11,513 Depreciation, depletion, amortization & accretion 2,143 2,880 6,734 8,705 General & administrative expense 701 671 2,308 2,605 Income from continuing operations 2,029 1,733 8,263 7,117 Net interest expense (629) (598) (1,582) (1,994) Net income $ 1,400 $ 1,135 $ 6,681 $ 5,123 Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2017 | |
Long-Term Debt [Abstract] | |
Long-Term Debt | 9. Long-Term Debt RBC Credit Facility In October 2013, the Company entered into a $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”), which matures on October 1, 2019. The borrowing base under the facility is redetermined each November and May. The Company is currently going through the redetermination process, but does not expect a material reduction that would affect its liquidity. As of September 30, 2017, the borrowing base under the RBC Credit Facility was $125 million. As of September 30, 2017, the Company had approximately $79.2 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2016, the Company had approximately $54.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of September 30, 2017, borrowing availability under the RBC Credit Facility was $43.9 million. Total interest expense under the RBC Credit Facility, including commitment fees, for the three and nine months ended September 30, 2017 was approximately $1.1 million and $2.8 million, respectively. Total interest expense under the RBC Credit Facility, including commitment fees, for the three and nine months ended September 30, 2016 was approximately $1.0 million and $3.0 million, respectively. The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of September 30, 2017, the Company was in compliance with all financial covenants under the RBC Credit Facility. The RBC Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. The weighted average interest rate in effect at September 30, 2017 and December 31, 2016 was 4.9% and 4.2%, respectively. The RBC Credit Facility matures on October 1, 2019, at which time any outstanding balances will be due. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2017 | |
Income Taxes [Abstract] | |
Income Taxes | 10. Income Taxes The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Current tax provision: Federal $ — $ — $ — $ — State 88 51 397 410 Total $ 88 $ 51 $ 397 $ 410 Total tax provision: Federal $ — $ — $ — $ — State 88 51 397 410 Total $ 88 $ 51 $ 397 $ 410 Included in gain from investment in affiliates $ — $ — $ — $ — Total income tax provision $ 88 $ 51 $ 397 $ 410 In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the nine months ended September 30, 2017, the Company continues to fully value the net deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 11. Related Party Transactions Olympic Energy Partners Mr. Joseph J. Romano, the Chairman of the Company’s board of directors, is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). Olympic participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to our Dutch and Mary Rose wells. During the three and nine months ended September 30, 2017, Mr. Romano earned $15 thousand and $42 thousand for his service as a director of the Company, respectively. During the three and nine months ended September 30, 2016, Mr. Romano earned $17 thousand and $43 thousand for his service as a director of the Company, respectively. In May 2017, Mr. Romano received 14,865 shares of restricted stock, which vest in one year, as part of his board of director compensation. The Company recognized compensation expense of approximately $28 thousand and $90 thousand related to the shares granted to Mr. Romano for the three and nine months ended September 30, 2017, respectively. In January 2016, Mr. Romano received 261 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program and an additional 9,892 shares of restricted stock in May 2016, which vest in one year, as part of his board of director compensation. During the three and nine months ended September 30, 2016, the Company recognized compensation expense of approximately $30 thousand and $70 thousand, respectively, related to the shares granted to Mr. Romano. Below is a summary of payments received from (paid to) Olympic in the ordinary course of business in the Company’s capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Revenue payments as well owners $ (634) $ (617) $ (2,071) $ (1,788) Joint interest billing receipts 111 149 306 272 As of September 30, 2017 and December 31, 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): September 30, 2017 December 31, 2016 Accounts receivable: Joint interest billing $ 26 $ 59 Accounts payable: Royalties and revenue payable (448) (557) Oaktree Capital Management L.P. As of September 30, 2017, Oaktree Capital Management L.P. ("Oaktree"), through various funds, owned approximately 5.1% of the Company's stock. On October 1, 2013, Mr. James Ford, then a Managing Director and Portfolio Manager within Oaktree, was elected to the Company's board of directors. Mr. Ford is currently a Senior Advisor to Oaktree. Historically, all cash and equity awards payable to Mr. Ford were instead granted to an affiliate of Oaktree. Beginning in October 2016, all cash and equity awards payable to Oaktree for Mr. Ford’s service as a director became payable to him directly. During the three and nine months ended September 30, 2017, Mr. Ford earned $18 thousand and $50 thousand in cash as a result of his board participation, respectively. During the three and nine months ended September 30, 2016, an affiliate of Oaktree earned $18 thousand and $50 thousand in cash as a result of Mr. Ford's board participation, respectively. In May 2017, Mr. Ford received 14,865 shares of restricted stock, which vest in one year, as part of his board of director compensation. The Company recognized compensation expense of approximately $28 thousand and $90 thousand related to the shares granted to Mr. Ford for the three and nine months ended September 30, 2017, respectively. In January 2016, an affiliate of Oaktree received 313 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program and an additional 9,892 shares of restricted stock in May 2016, which vest in one year, as part of Mr. Ford’s board of director compensation. During the three and nine months ended September 30, 2016, the Company recognized compensation expense of approximately $30 thousand and $70 thousand, respectively, related to the shares granted to an affiliate of Oaktree. |
Commitments And Contingencies
Commitments And Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | 12. Commitments and Contingencies Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. In July 2010, several parties associated with a limited partnership, formed to invest in oil and gas properties, that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The plaintiffs’ expert has provided a range of estimated monetary damages of up to approximately $9.4 million as to the Company’s subsidiary. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses. In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing the trial court’s decision to the applicable state Court of Appeals. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff is appealing the trial court’s decision to the applicable state Court of Appeals. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit. While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely. Throughput Contract Commitment The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. The Company currently forecasts that monthly gas volume deliveries through this line in its Southeast Texas area will not meet minimum throughput requirements under the agreement. Without further development in that area, the volume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in April of each calendar year. The Company estimates that the net deficiency fee will be approximately $1.0 million annually for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. As of September 30, 2017, based upon the current commodity price market and our short term strategic drilling plans, the Company has recorded a $0.8 million loss contingency through December 31, 2017. The Company will continue to assess this commitment in light of its development plans for this area. |
Summary Of Significant Accoun19
Summary Of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Summary Of Significant Accounting Policies [Abstract] | |
Basis Of Presentation | Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2016 Form 10-K. The consolidated results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. |
Principles Of Consolidation | The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by our wholly owned subsidiary, Contaro Company (“Contaro”) is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results. |
Oil and Gas Properties - Successful Efforts | Oil and Gas Properties - Successful Efforts Our application of the successful efforts method of accounting for our natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized no impairment of proved properties for the three and nine months ended September 30, 2017. No impairment of proved properties was recognized for the three months ended September 30, 2016, and the Company recognized approximately $0.7 million impairment of proved properties for the nine months ended September 30, 2016, substantially all of which was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized no impairment of unproved properties for the three months ended September 30, 2017 and $1.4 million in impairment expense related to the partial impairment of two unused offshore platforms for the nine months ended September 30, 2017. The Company recognized impairment expense of approximately $1.1 million and approximately $3.4 million for the three and nine months ended September 30, 2016, respectively, related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases, substantially all of which was related to unproved lease cost amortization of marginal, non-core properties in Fayette and Gonzales counties, Texas. |
Net Loss Per Common Share | Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, Performance Stock Units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three months ended September 30, 2017, the Company excluded 971,813 potentially dilutive securities, as they were antidilutive, and excluded 813,151 potentially dilutive securities for the nine months ended September 30, 2017, as they were antidilutive. For the three months ended September 30, 2016, the Company excluded 439,017 potentially dilutive securities, as they were antidilutive, and 382,867 potentially dilutive securities were excluded for the nine months ended September 30, 2016, as they were antidilutive. |
Subsidiary Guarantees | Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. Finally, the Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its initial review of all revenue contracts. The Company’s revenue contracts are normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value Of Financial Assets And (Liabilities) | Fair value information for financial assets and liabilities was as follows as of September 30, 2017 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 440 $ — $ 440 $ — Commodity price contracts - liabilities $ (90) $ — $ (90) $ — |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Schedule Of Derivative Contracts | The following derivative instruments were in place at September 30, 2017 (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Oct 2017 Collar 200,000 MMBtu $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Oct 2017 Swap 70,000 MMBtu $ Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtu $ Oil Oct 2017 Swap 6,000 Bbls $ Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ Oil Oct 2017 - Dec 2017 Swap 9,000 Bbls $ Total net fair value of derivative instruments $ 350 (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable. |
Schedule Of Fair Value Of Commodity Derivatives | The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2017 (in thousands): Gross Netting (1) Total Assets $ 440 $ — $ 440 Liabilities $ (90) $ — $ (90) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2016 (in thousands): Gross Netting (1) Total Assets $ — $ — $ — Liabilities $ (3,446) $ — $ (3,446) (1) Represents counterparty netting under agreements governing such derivatives. |
Schedule Of Derivative Contracts On Operations | The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Crude oil contracts $ 342 $ — $ 879 $ — Natural gas contracts 179 (619) (102) 3,136 Realized gain (loss) $ 521 $ (619) $ 777 $ 3,136 Crude oil contracts $ (661) $ — $ 156 $ — Natural gas contracts 131 1,532 3,641 (2,400) Unrealized gain (loss) $ (530) $ 1,532 $ 3,797 $ (2,400) Gain (loss) on derivatives, net $ (9) $ 913 $ 4,574 $ 736 |
Subsequent Derivative Contracts [Member] | |
Schedule Of Derivative Contracts | In October 2017, the Company entered into the following additional financial derivative contracts with a member of its credit facility lenders: Commodity Period Derivative Volume/Month Price/Unit (1) Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtu $ 3.07 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtu $ 3.07 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtu $ 3.07 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and Argus Louisiana Light Sweet oil prices, as applicable. |
Other Financial Information (Ta
Other Financial Information (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Other Financial Information [Abstract] | |
Schedule Of Additional Financial Details | The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): September 30, 2017 December 31, 2016 Accounts receivable: Trade receivables $ 7,262 $ 8,424 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 2,972 3,519 Income taxes receivable 92 91 Other receivables 335 3,395 Allowance for doubtful accounts (897) (695) Total accounts receivable $ 11,757 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 1,088 $ 1,086 Other 698 701 Total prepaid expenses and other $ 1,786 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 19,343 $ 16,920 Advances from partners 3,230 5,792 Accrued exploration and development 8,189 11,176 Accrued carried well costs — 7,155 Trade payables 5,433 5,406 Accrued LOE & workover expense 2,228 1,867 Accrued G&A and legal expense 3,997 5,016 Other accounts payable and accrued liabilities 2,981 1,803 Total accounts payable and accrued liabilities $ 45,401 $ 55,135 |
Schedule Of Supplemental Disclosures | Included in the table below is supplemental information about certain cash and non-cash transactions during the nine months ended September 30, 2017 and 2016 (in thousands): Nine Months Ended September 30, 2017 2016 Cash payments: Interest payments $ 2,501 $ 2,935 Income tax payments (refunds) $ 708 $ (2,337) Non-cash investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures $ (10,142) $ 7,248 |
Investment In Exaro Energy II23
Investment In Exaro Energy III LLC (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Investment In Exaro Energy III LLC [Abstract] | |
Schedule Of Condensed Balance Sheet Data | September 30, 2017 December 31, 2016 Current assets (1) $ 15,897 $ 25,296 Non-current assets: Net property and equipment 84,766 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 57 8 Total non-current assets 85,973 91,779 Total assets $ 101,870 $ 117,075 Current liabilities (2) $ 3,950 $ 65,694 Non-current liabilities: Long-term debt 44,356 — Other non-current liabilities 3,466 8,106 Total non-current liabilities 47,822 8,106 Members' equity 50,098 43,275 Total liabilities & members' equity $ 101,870 $ 117,075 (1) Approximately $13.6 million and $19.6 million of current assets as of September 30, 2017 and December 31, 2016, respectively, is cash. (1) Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced. |
Schedule Of Condensed Income Statement Data | Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Production: Oil (thousand barrels) 24 30 77 98 Gas (million cubic feet) 2,216 2,659 6,797 8,083 Total (million cubic feet equivalent) 2,360 2,839 7,260 8,671 Oil and natural gas sales $ 7,483 $ 8,242 $ 24,499 $ 20,730 Gain (loss) on derivatives 318 1,011 3,720 (1,231) Other gain — — — 10,441 Less: Lease operating expenses 2,928 3,969 10,914 11,513 Depreciation, depletion, amortization & accretion 2,143 2,880 6,734 8,705 General & administrative expense 701 671 2,308 2,605 Income from continuing operations 2,029 1,733 8,263 7,117 Net interest expense (629) (598) (1,582) (1,994) Net income $ 1,400 $ 1,135 $ 6,681 $ 5,123 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Income Taxes [Abstract] | |
Components Of Income Tax Expense (Benefit) | The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Current tax provision: Federal $ — $ — $ — $ — State 88 51 397 410 Total $ 88 $ 51 $ 397 $ 410 Total tax provision: Federal $ — $ — $ — $ — State 88 51 397 410 Total $ 88 $ 51 $ 397 $ 410 Included in gain from investment in affiliates $ — $ — $ — $ — Total income tax provision $ 88 $ 51 $ 397 $ 410 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Related Party Transactions [Abstract] | |
Schedule Of Payments Received From (Made To) Related Parties | The Company made and received similar types of payments with other well owners (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Revenue payments as well owners $ (634) $ (617) $ (2,071) $ (1,788) Joint interest billing receipts 111 149 306 272 |
Schedule Of Related Party Balances | As of September 30, 2017 and December 31, 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): September 30, 2017 December 31, 2016 Accounts receivable: Joint interest billing $ 26 $ 59 Accounts payable: Royalties and revenue payable (448) (557) |
Organization And Business (Deta
Organization And Business (Details) | 9 Months Ended | |
Sep. 30, 2017aft | Jul. 31, 2016a | |
Southern Delaware Basin Of Texas [Member] | ||
Gas and Oil Acreage [Line Items] | ||
Gross acres - Undeveloped | 12,100 | |
Net acres - Undeveloped | 5,000 | |
Gross acres - Operated | 13,600 | |
Net acres - Operated | 6,800 | |
Exaro Energy III LLC [Member] | ||
Gas and Oil Acreage [Line Items] | ||
Equity method investment, ownership percentage | 37.00% | |
Maximum [Member] | ||
Gas and Oil Acreage [Line Items] | ||
Water depth of operations | ft | 300 |
Summary Of Significant Accoun27
Summary Of Significant Accounting Policies (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017USD ($)shares | Sep. 30, 2016USD ($)shares | Sep. 30, 2017USD ($)itemshares | Sep. 30, 2016USD ($)shares | Dec. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |||||
Impairment of proved properties | $ | $ 0 | $ 0 | $ 0 | $ 0.7 | |
Impairment charges, unproved properties | $ | $ 0 | $ 1.1 | $ 1.4 | $ 3.4 | |
Number of platforms | item | 2 | ||||
Antidilutive (in shares) | shares | 971,813 | 439,017 | 813,151 | 382,867 | |
Restricted assets, percent of net assets | 25.00% | ||||
Number of subsidiaries inactive and not Subsidiary Guarantor | item | 1 |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Details) | Feb. 01, 2017USD ($) | Jul. 31, 2016USD ($)aitem | Sep. 30, 2017USD ($)a | Dec. 31, 2016USD ($) | Dec. 30, 2016USD ($)a |
Acquisition | |||||
Carried well cost | $ 7,155,000 | ||||
Southern Delaware Basin Of Texas [Member] | |||||
Acquisition | |||||
Percentage of working interest acquired | 50.00% | ||||
Gross acres - Undeveloped | a | 12,100 | ||||
Net acres - Undeveloped | a | 5,000 | ||||
Cash consideration for acquisition | $ 10,000,000 | ||||
Carried cost payments | $ 10,000,000 | ||||
Spud bonus | $ 700,000 | ||||
Gross acres - Operated | a | 13,600 | ||||
Net acres - Operated | a | 6,800 | ||||
Southern Delaware Basin Of Texas [Member] | Maximum [Member] | |||||
Acquisition | |||||
Estimated consideration | 25,000,000 | ||||
Disposal Group Disposed Of By Sale Not Discontinued Operations [Member] | Colorado Properties [Member] | |||||
Acquisition | |||||
Aggregate sales price of assets sold | $ 5,000,000 | ||||
Gas and Oil Area, Developed, Gross | a | 16,000 | ||||
Gas and Oil Area, Developed, Net | a | 11,200 | ||||
Disposal Group Disposed Of By Sale Not Discontinued Operations [Member] | Southeast Texas Assets [Member] | |||||
Acquisition | |||||
Aggregate sales price of assets sold | $ 650,000 | ||||
Gain on sale of oil and gas property | $ 2,900,000 | ||||
Phase One [Member] | Southern Delaware Basin Of Texas [Member] | |||||
Acquisition | |||||
Carried well cost | $ 10,000,000 | ||||
Number of wells | item | 6 | ||||
Phase Two [Member] | Southern Delaware Basin Of Texas [Member] | |||||
Acquisition | |||||
Spud bonus | $ 5,000,000 | ||||
Number of wells | item | 14 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2017USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Commodity price contracts - assets | $ 440 |
Commodity price contracts - liabilities | (90) |
Level 2 [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Commodity price contracts - assets | 440 |
Commodity price contracts - liabilities | $ (90) |
RBC Credit Facility [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Maximum period of interest rate on floating-rate debt | 6 months |
Derivative Instruments (Derivat
Derivative Instruments (Derivative Contracts) (Details) $ in Thousands | 1 Months Ended | 9 Months Ended |
Oct. 31, 2017item$ / bbl$ / Mcf | Sep. 30, 2017USD ($)item$ / bbl$ / Mcf | |
Derivative [Line Items] | ||
Fair Value | $ | $ 350 | |
Derivative Contract Period October 2017 [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 0 | |
Commodity Derivative Flow Rate | 200,000 | |
Derivative Contract Period October 2017 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 37 | |
Commodity Derivative Flow Rate | 70,000 | |
Price/Unit-Swap | $ / Mcf | 3.51 | |
Derivative Contract Period October 2017 [Member] | Swap [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 13 | |
Commodity Derivative Flow Rate | 6,000 | |
Price/Unit-Swap | $ / bbl | 53.95 | |
Derivative Contract Period October 2017 [Member] | Minimum [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / Mcf | 2.65 | |
Derivative Contract Period October 2017 [Member] | Maximum [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / Mcf | 3 | |
Derivative Contract Period October to December 2017 [Member] | Swap [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 114 | |
Commodity Derivative Flow Rate | 9,000 | |
Price/Unit-Swap | $ / bbl | 56.20 | |
Derivative Contract Period, November to December 2017 [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ (90) | |
Commodity Derivative Flow Rate | 400,000 | |
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 246 | |
Commodity Derivative Flow Rate | 300,000 | |
Price/Unit-Swap | $ / Mcf | 3.51 | |
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ | $ 30 | |
Commodity Derivative Flow Rate | 8,000 | |
Price/Unit-Swap | $ / bbl | 53.95 | |
Derivative Contract Period, November to December 2017 [Member] | Minimum [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / Mcf | 2.65 | |
Derivative Contract Period, November to December 2017 [Member] | Maximum [Member] | Collar Options [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / Mcf | 3 | |
Derivative Contract Period January To June 2018 [Member] | Swap [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 20,000 | |
Price/Unit-Swap | $ / bbl | 56.40 | |
Derivative Contract Period January To July 2018 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 370,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Derivative Contract Period July To October 2018 [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 20,000 | |
Derivative Contract Period July To October 2018 [Member] | Minimum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 52 | |
Derivative Contract Period July To October 2018 [Member] | Maximum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 56.85 | |
Derivative Contract Period August To October 2018 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 70,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Derivative Contract Period November To December 2018 [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 15,000 | |
Derivative Contract Period November To December 2018 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 320,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Derivative Contract Period November To December 2018 [Member] | Minimum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 52 | |
Derivative Contract Period November To December 2018 [Member] | Maximum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 56.85 | |
Derivative Contract Period, January to December 2019 [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Commodity Derivative Flow Rate | 7,000 | |
Derivative Contract Period, January to December 2019 [Member] | Minimum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 50 | |
Derivative Contract Period, January to December 2019 [Member] | Maximum [Member] | Collar Options [Member] | Oil [Member] | ||
Derivative [Line Items] | ||
Price/Unit-Swap | $ / bbl | 58 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Assets | ||
Total | $ 440 | |
Liabilities: | ||
Total | (90) | |
Commodity Derivatives [Member] | ||
Assets | ||
Gross | 440 | |
Total | 440 | |
Liabilities: | ||
Gross | (90) | $ (3,446) |
Total | $ (90) | $ (3,446) |
Derivative Instruments (Operati
Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | $ 521 | $ (619) | $ 777 | $ 3,136 |
Unrealized gain (loss) | (530) | 1,532 | 3,797 | (2,400) |
Gain (loss) on derivatives, net | (9) | 913 | 4,574 | 736 |
Oil [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | 342 | 879 | ||
Unrealized gain (loss) | (661) | 156 | ||
Natural Gas [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | 179 | (619) | (102) | 3,136 |
Unrealized gain (loss) | $ 131 | $ 1,532 | $ 3,641 | $ (2,400) |
Stock Based Compensation (NonOp
Stock Based Compensation (NonOption) (Details) - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2015 | |
Restricted Stock [Member] | |||
Activity, weighted average fair value | |||
Granted (in dollars per share) | $ 7.55 | $ 11.60 | |
Stock-based compensation | |||
Value of issued stock after adjustment for estimated forfeiture rate | $ 3,500 | $ 3,300 | |
Weighted average forfeiture rate | 5.70% | 3.50% | |
Value of restricted shares forfeited | $ 1,300 | $ 130 | |
Available for grant, end of year (in shares) | 1,600,000 | ||
Stock-based compensation expense | $ 4,600 | $ 4,300 | |
Compensation expense not yet recognized | $ 6,200 | ||
Compensation expense, remaining weighted average vesting period | 2 years 1 month 6 days | ||
Target (as a percent) | 100.00% | ||
Performance Stock Units [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 0 | ||
Canceled/Forfeited (in shares) | 94,063 | 0 | |
Stock-based compensation | |||
Vesting period | 3 years | ||
New Employees [Member] | Performance Stock Units [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 30,000 | ||
Activity, weighted average fair value | |||
Granted (in dollars per share) | $ 8.32 | ||
Employees [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 197,306 | ||
Stock-based compensation | |||
Vesting period | 4 years | ||
New And Existing Employees [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 383,376 | ||
Stock-based compensation | |||
Vesting period | 3 years | ||
Board of Directors [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 74,325 | 49,460 | |
Stock-based compensation | |||
Vesting period | 1 year | 1 year | |
Former Employee [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Canceled/Forfeited (in shares) | 128,615 | 4,160 | |
Executives [Member] | Performance Stock Units [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 160,908 | ||
Activity, weighted average fair value | |||
Granted (in dollars per share) | $ 13.91 | ||
Minimum [Member] | Performance Stock Units [Member] | |||
Stock-based compensation | |||
Target (as a percent) | 0.00% | ||
Maximum [Member] | Performance Stock Units [Member] | |||
Stock-based compensation | |||
Target (as a percent) | 300.00% | ||
Salary Replacement Plan [Member] | |||
Stock-based compensation | |||
Salary deferred (as a percent) | 10.00% | ||
Salary Replacement Plan [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 40,876 | ||
Salary Replacement Plan [Member] | Employees [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 38,943 | ||
Salary Replacement Plan [Member] | Board of Directors [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Granted non-option (in shares) | 1,933 |
Stock Based Compensation (Optio
Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($) | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Option roll forward | ||
Stock options granted in period (in shares) | 0 | 0 |
Exercise of stock options, shares | 0 | 0 |
Options forfeitures during the period (in shares) | 17,072 | 1,657 |
Stock-based compensation | ||
Excess tax benefit from exercise/cancellation of stock options | $ 0 | $ 0 |
Other Financial Information (Ba
Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Accounts Receivable: | ||
Trade receivables | $ 7,262 | $ 8,424 |
Receivable for Alta Resources Distribution | 1,993 | 1,993 |
Joint interest billings | 2,972 | 3,519 |
Income taxes receivable | 92 | 91 |
Other receivables | 335 | 3,395 |
Allowance for doubtful accounts | (897) | (695) |
Total Accounts Receivable | 11,757 | 16,727 |
Prepaid expenses and other: | ||
Prepaid insurance | 1,088 | 1,086 |
Other | 698 | 701 |
Total prepaid expenses and other | 1,786 | 1,787 |
Accounts payable and accrued liabilities: | ||
Royalties and revenue payable | 19,343 | 16,920 |
Advances from partners | 3,230 | 5,792 |
Accrued exploration and development | 8,189 | 11,176 |
Accrued carried well costs | 7,155 | |
Trade payables | 5,433 | 5,406 |
Accrued LOE & workover expense | 2,228 | 1,867 |
Accrued G&A and legal expense | 3,997 | 5,016 |
Other accounts payable and accrued liabilities | 2,981 | 1,803 |
Total Accounts Payable and Accrued Liabilities | $ 45,401 | $ 55,135 |
Other Financial Information (Su
Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Cash payments: | ||
Interest payments | $ 2,501 | $ 2,935 |
Income tax payments (refunds) | 708 | (2,337) |
Non-cash investing activities in the consolidated statements of cash flows: | ||
Increase (decrease) in accrued capital expenditures | $ (10,142) | $ 7,248 |
Investment in Exaro Energy II37
Investment in Exaro Energy III LLC (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Schedule of Equity Method Investments Financials | ||||
Gain from investment in affiliates, net of income taxes | $ 525 | $ 467 | $ 2,475 | $ 1,802 |
Exaro Energy III LLC [Member] | ||||
Schedule of Equity Method Investments Financials | ||||
Equity method investment, ownership percentage | 37.00% | 37.00% | ||
Share of equity in investment | $ 18,100 | $ 18,100 | ||
Gain from investment in affiliates, net of income taxes | 500 | 500 | 2,500 | 1,800 |
Tax (expense) benefit from equity investment | $ 0 | $ 0 | $ 0 | $ 0 |
Investment in Exaro Energy II38
Investment in Exaro Energy III LLC (Balance Sheet) (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2016 |
Non-current assets: | |||
Net property and equipment | $ 342,615 | $ 340,382 | |
Other non-current assets | 19,196 | 17,078 | |
Non-current liabilities: | |||
Other non-current liabilities | 248 | 248 | |
Cash and cash equivalents | |||
Exaro Energy III LLC [Member] | |||
Schedule of Equity Method Investments Financials | |||
Current assets | 15,897 | 25,296 | |
Non-current assets: | |||
Net property and equipment | 84,766 | 90,621 | |
Gas processing deposit | 1,150 | 1,150 | |
Other non-current assets | 57 | 8 | |
Total non-current assets | 85,973 | 91,779 | |
Total assets | 101,870 | 117,075 | |
Current liabilities | 3,950 | 65,694 | |
Non-current liabilities: | |||
Long-term debt | 44,356 | ||
Other non-current liabilities | 3,466 | 8,106 | |
Total non-current liabilities | 47,822 | 8,106 | |
Member's equity | 50,098 | 43,275 | |
Total liabilities & member's equity | 101,870 | 117,075 | |
Cash and cash equivalents | $ 13,600 | 19,600 | |
Current debt | $ 59,300 |
Investment in Exaro Energy II39
Investment in Exaro Energy III LLC (Income Statement) (Details) MMcfe in Thousands, MMcf in Thousands, MBbls in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||||||||||
Sep. 30, 2017MMcf | Sep. 30, 2017MBbls | Sep. 30, 2017MMcfe | Sep. 30, 2017USD ($) | Sep. 30, 2016MMcf | Sep. 30, 2016MBbls | Sep. 30, 2016MMcfe | Sep. 30, 2016USD ($) | Sep. 30, 2017MMcf | Sep. 30, 2017MBbls | Sep. 30, 2017MMcfe | Sep. 30, 2017USD ($) | Sep. 30, 2016MMcf | Sep. 30, 2016MBbls | Sep. 30, 2016MMcfe | Sep. 30, 2016USD ($) | |
Schedule of Equity Method Investments Financials | ||||||||||||||||
Gain (loss) on derivatives, net | $ (9) | $ 913 | $ 4,574 | $ 736 | ||||||||||||
General & administrative expense | 6,219 | 7,486 | 18,648 | 18,772 | ||||||||||||
Net income | (12,065) | (41,185) | ||||||||||||||
Exaro Energy III LLC [Member] | ||||||||||||||||
Schedule of Equity Method Investments Financials | ||||||||||||||||
Production | 2,216 | 24 | 2,659 | 30 | 6,797 | 77 | 8,083 | 98 | ||||||||
Total Production (Mcfe) | MMcfe | 2,360 | 2,839 | 7,260 | 8,671 | ||||||||||||
Oil and natural gas sales | 7,483 | 8,242 | 24,499 | 20,730 | ||||||||||||
Gain (loss) on derivatives, net | 318 | 1,011 | 3,720 | (1,231) | ||||||||||||
Other gain | 10,441 | |||||||||||||||
Lease operating expenses | 2,928 | 3,969 | 10,914 | 11,513 | ||||||||||||
Depreciation, depletion, amortization & accretion | 2,143 | 2,880 | 6,734 | 8,705 | ||||||||||||
General & administrative expense | 701 | 671 | 2,308 | 2,605 | ||||||||||||
Income from continuing operations | 2,029 | 1,733 | 8,263 | 7,117 | ||||||||||||
Net interest expense | (629) | (598) | (1,582) | (1,994) | ||||||||||||
Net income | $ 1,400 | $ 1,135 | $ 6,681 | $ 5,123 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Oct. 31, 2013USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | |
Debt Instrument [Line Items] | ||||||
Arrangement fee | $ 996 | |||||
Letters of credit amount outstanding | $ 1,900 | $ 1,900 | $ 1,900 | |||
Interest expense | $ 1,138 | $ 989 | $ 2,822 | 3,045 | ||
Weighted average interest rate (as a percent) | 4.90% | 4.90% | 4.20% | |||
RBC Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Revolving credit facility, maximum borrowing capacity | $ 500,000 | |||||
Revolving credit facility, borrowing base | $ 125,000 | $ 125,000 | ||||
Credit facility amount outstanding | 79,200 | 79,200 | $ 54,400 | |||
Line of credit, available | 43,900 | 43,900 | ||||
Interest expense | $ 1,100 | $ 1,000 | $ 2,800 | $ 3,000 | ||
RBC Credit Facility [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Current ratio | 1 | |||||
RBC Credit Facility [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Leverage ratio | 3.50 |
Income Taxes (Expense Benefit)
Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Current: | ||||
State | $ 88 | $ 51 | $ 397 | $ 410 |
Total | 88 | 51 | 397 | 410 |
Total: | ||||
State | 88 | 51 | 397 | 410 |
Total | 88 | 51 | 397 | 410 |
Income tax provision | $ 88 | $ 51 | $ 397 | $ 410 |
Related Party Transactions (Oly
Related Party Transactions (Olympic) (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
May 31, 2017 | May 31, 2016 | Jan. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Accounts receivable: | ||||||||
Joint interest billing | $ 2,972 | $ 2,972 | $ 3,519 | |||||
Olympic [Member] | ||||||||
Related Party Transaction [Line Items] | ||||||||
Revenue payments as well owners | (634) | $ (617) | (2,071) | $ (1,788) | ||||
Joint interest billing receipts | 111 | 149 | 306 | 272 | ||||
Accounts receivable: | ||||||||
Joint interest billing | 26 | 26 | 59 | |||||
Accounts payable: | ||||||||
Royalties and revenue payable | (448) | (448) | $ (557) | |||||
Mr. Romano [Member] | ||||||||
Related Party Transaction [Line Items] | ||||||||
Director compensation for related party | 15 | 17 | 42 | 43 | ||||
Restricted Stock [Member] | ||||||||
Related Party Transaction [Line Items] | ||||||||
Stock-based compensation expense | 4,600 | 4,300 | ||||||
Restricted Stock [Member] | Mr. Romano [Member] | ||||||||
Related Party Transaction [Line Items] | ||||||||
Restricted stock granted in period (in shares) | 14,865 | 9,892 | 261 | |||||
Vesting period | 1 year | 1 year | ||||||
Stock-based compensation expense | $ 28 | $ 30 | $ 90 | $ 70 | ||||
Performance Stock Units [Member] | ||||||||
Related Party Transaction [Line Items] | ||||||||
Restricted stock granted in period (in shares) | 0 | |||||||
Vesting period | 3 years |
Related Party Transactions (Oak
Related Party Transactions (Oaktree) (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
May 31, 2017 | May 31, 2016 | Jan. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
James Ford [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Director compensation for related party | $ 18 | $ 18 | $ 50 | $ 50 | |||
Oaktree [Member] | Contango [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Ownership Percentage in Company's Stock | 5.10% | 5.10% | |||||
Restricted Stock [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Stock-based compensation expense | $ 4,600 | 4,300 | |||||
Restricted Stock [Member] | James Ford [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Restricted stock granted in period (in shares) | 14,865 | 9,892 | 313 | ||||
Vesting period | 1 year | 1 year | |||||
Stock-based compensation expense | $ 28 | $ 30 | $ 90 | $ 70 |
Commitments And Contingencies (
Commitments And Contingencies (Narrative) (Details) $ in Millions | 1 Months Ended | 9 Months Ended | ||
Sep. 30, 2012USD ($) | Nov. 30, 2010USD ($)site | Jul. 31, 2010USD ($) | Sep. 30, 2017USD ($) | |
Throughput commitment | ||||
Loss Contingency | ||||
Estimated deficiency | $ 1 | |||
Loss contingency expense | $ 0.8 | |||
Madison County Case [Member] | ||||
Legal Proceedings | ||||
Damages sought by plaintiffs | $ 9.4 | |||
Lavaca County Case [Member] | ||||
Legal Proceedings | ||||
Damages sought by plaintiffs | $ 5.3 | |||
Number of wells involved in litigation | site | 2 | |||
Litigation Case Filed by Mineral Interest Owner Harris County [Member] | ||||
Legal Proceedings | ||||
Damages sought by plaintiffs | $ 10.7 | |||
Additional portion of mineral interest claimed by plaintiff | 6.25% |