10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

DELAWARE	95-4079863
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
717 TEXAS AVENUE, SUITE 2900 HOUSTON, TEXAS	77002
(Address of principal executive offices)	(Zip Code)

(713) 236-7400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, Par Value $0.04 per share	MCF	NYSE American

The total number of shares of common stock, par value $0.04 per share, outstanding as of May 3, 2019 was 34,400,594.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2019 

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of March 31, 2019 and December 31, 2018	3
	Consolidated Statements of Operations (unaudited) for the three months ended March 31, 2019 and 2018	4
	Consolidated Statements of Cash Flows (unaudited) for the three months ended March 31, 2019 and 2018	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the three months ended March 31, 2019 and March 2018	6
	Notes to the Consolidated Financial Statements (unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	32
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	34

All references in this Quarterly Report on Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its subsidiaries.

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Item 1.Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)

	March 31,		December 31,
	2019		2018
	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—
Accounts receivable, net		11,530		11,531
Prepaid expenses		468		1,303
Current derivative asset		1,371		4,600
Other current assets		112		—
Total current assets		13,481		17,434
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		1,096,714		1,095,417
Unproved properties		35,538		34,612
Other property and equipment		1,331		1,314
Accumulated depreciation, depletion and amortization		(905,437)		(898,169)
Total property, plant and equipment, net		228,146		233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates		6,053		5,743
Deferred tax asset		—		424
Other non-current assets		352		357
Total other non-current assets		6,405		6,524
TOTAL ASSETS	$	248,032	$	257,132
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	32,188	$	39,506
Current derivative liability		839		422
Current asset retirement obligations		1,373		1,329
Current portion of long-term debt		65,552		60,000
Total current liabilities		99,952		101,257
NON-CURRENT LIABILITIES:
Long-term debt		—		—
Asset retirement obligations		12,108		12,168
Other long term liabilities		3,421		3,318
Total non-current liabilities		15,529		15,486
Total liabilities		115,481		116,743
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 39,925,092 shares issued and 34,416,727 shares outstanding at March 31, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018		1,585		1,573
Additional paid-in capital		340,935		339,981
Treasury shares at cost (5,508,365 shares at March 31, 2019 and 5,458,950 shares at December 31, 2018)		(129,216)		(129,030)
Retained earnings (deficit)		(80,753)		(72,135)
Total shareholders’ equity		132,551		140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	248,032	$	257,132

The accompanying notes are an integral part of these consolidated financial statements

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Three Months Ended
	March 31,
	2019		2018
	(unaudited)
REVENUES:
Oil and condensate sales	$	6,406	$	8,811
Natural gas sales		5,642		8,609
Natural gas liquids sales		1,963		3,017
Total revenues		14,011		20,437
EXPENSES:
Operating expenses		5,192		6,927
Exploration expenses		224		469
Depreciation, depletion and amortization		7,556		10,485
Impairment and abandonment of oil and gas properties		587		3,327
General and administrative expenses		5,005		6,726
Total expenses		18,564		27,934
OTHER INCOME (EXPENSE):
Gain from investment in affiliates, net of income taxes		30		707
Gain (loss) from sale of assets		(12)		9,447
Interest expense		(1,092)		(1,409)
Loss on derivatives, net		(2,878)		(1,032)
Other income (expense)		(86)		879
Total other income (expense)		(4,038)		8,592
NET INCOME (LOSS) BEFORE INCOME TAXES		(8,591)		1,095
Income tax provision		(27)		(158)
NET INCOME (LOSS)	$	(8,618)	$	937
NET INCOME (LOSS) PER SHARE:
Basic	$	(0.26)	$	0.04
Diluted	$	(0.26)	$	0.04
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		33,770		24,793
Diluted		33,770		24,841

The accompanying notes are an integral part of these consolidated financial statements

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended
	March 31,
	2019		2018
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(8,618)	$	937
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		7,556		10,485
Impairment of natural gas and oil properties		483		3,097
Deferred income taxes		424		—
Loss (gain) on sale of assets		12		(9,447)
Gain from investment in affiliates		(30)		(707)
Stock-based compensation		1,052		1,424
Unrealized loss on derivative instruments		3,646		519
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other receivables		146		(642)
Decrease in prepaids		835		940
Decrease in accounts payable & advances from joint owners		(4,299)		(6,053)
Decrease in other accrued liabilities		(826)		(1,921)
Increase in income taxes receivable, net		(424)		—
Increase in income taxes payable, net		27		158
Other		(123)		3,279
Net cash provided by (used in) operating activities	$	(139)	$	2,069
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	$	(5,124)	$	(16,244)
Additions to furniture & equipment		(17)		—
Sale of oil & gas properties		—		20,965
Net cash provided by (used in) investing activities	$	(5,141)	$	4,721
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	37,025	$	74,832
Repayments under credit facility		(31,473)		(81,551)
Net costs from equity offering		(86)		—
Purchase of treasury stock		(186)		(71)
Net cash provided by (used in) financing activities	$	5,280	$	(6,790)
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	—	$	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—	$	—

The accompanying notes are an integral part of these consolidated financial statements

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the three months ended March 31, 2019

(in thousands, except number of shares)

				Additional						Total
	Common Stock			Paid-in		Treasury		Retained		Shareholders’
	Shares	Amount		Capital		Stock		Earnings		Equity
	(unaudited)
Balance at December 31, 2018	34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering costs	—		—		(86)		—		—		(86)
Treasury shares at cost	(49,415)		—		—		(186)		—		(186)
Restricted shares activity	307,650		12		(12)		—		—		—
Stock-based compensation	—		—		1,052		—		—		1,052
Net loss	—		—		—		—		(8,618)		(8,618)
Balance at March 31, 2019	34,416,727	$	1,585	$	340,935	$	(129,216)	$	(80,753)	$	132,551

The accompanying notes are an integral part of these consolidated financial statements

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the three months ended March 31, 2018

(in thousands, except number of shares)

				Additional						Total
	Common Stock			Paid-in		Treasury		Retained		Shareholders’
	Shares	Amount		Capital		Stock		Earnings		Equity
	(unaudited)
Balance at December 31, 2017	25,505,715	$	1,223	$	302,527	$	(128,583)	$	49,433	$	224,600
Treasury shares at cost	(16,032)		—		—		(71)		—		(71)
Restricted shares activity	206,114		8		(8)		—		—		—
Stock-based compensation	—		—		1,424		—		—		1,424
Net income	—		—		—		—		937		937
Balance at March 31, 2018	25,695,797	$	1,231	$	303,943	$	(128,654)	$	50,370	$	226,890

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States.

The following table lists the Company’s primary producing areas as of March 31, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp
Madison and Grimes counties, Texas	Woodbine (Upper Lewisville)
Zavala and Dimmit counties, Texas	Buda / Eagle Ford / Georgetown
San Augustine County, Texas	Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast	Conventional and smaller unconventional formations
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 all periods shown in this report.

The Company has recently been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas, which is expected to continue to generate positive returns on its drilling investment in the current price environment. As of March 31, 2019, the Company was producing from twelve wells over its 17,700 gross operated (8,200 total net) acre position in this West Texas area,  prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

The Company currently expects this acreage in West Texas to be the primary focus of its drilling program for 2019. Until a sustained improvement in commodity prices occurs, the Company will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas. The Company will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales.  Throughout all this, the Company will continue to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves. 

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, 2018 (the “2018 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2018 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,

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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 2018 Form 10-K. These unaudited interim consolidated results of operations for the quarter ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019.

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 the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations.

Liquidity and Going Concern

Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its Credit Facility (as defined in Note 10 – “Indebtedness”), which matures on October 1, 2019. The refinancing or replacement of the Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment 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, probable and possible reserves, future commodity prices, the timing of future

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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. No impairment of proved properties was recognized during the quarter ended March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018.

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 impairment expense of approximately $0.5 million and approximately $0.8 million for quarters ended March 31, 2019 and 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Income (Loss) Per Common Share 

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (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 quarter ended March 31, 2019, the Company excluded 526,309 shares or units of potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2018, the Company excluded 670,210 shares or units of potentially dilutive securities, 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. 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.

Revenue Recognition

Adoption of ASC 606

As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

Revenue from Contracts with Customers

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the

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past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. 

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606.

Transaction Price Allocated to Remaining Performance Obligations

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required.

Contract Balances

The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process.

Impact of Adoption of ASC 606

The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the quarter ended March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after

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December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

3. Acquisitions and Dispositions  

On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.4 million, prior to final closing adjustments.

4. Fair Value Measurements

Pursuant to Accounting Standards Codification Topic 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 March 31, 2019. 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 March 31, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	1,371	$	—	$	1,371	$	—
Commodity price contracts - liabilities	$	(839)	$	—	$	(839)	$	—

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 "Loss on derivatives, net" in its 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 reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives.

As of March 31, 2019, the Company's derivative contracts were all with certain members of its Credit Facility lending group, 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 Accounting Standards Codification Topic 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

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value due to their short-term nature. The estimated fair value of the Company's Credit Facility approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 - "Indebtedness" for further information.

Impairments

The Company 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, probable and possible 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.

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 March 31, 2019, 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 Credit Facility. See Note 10 – “Indebtedness” for further information regarding the 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

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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 “Loss on derivatives, net” on the consolidated statements of operations.

As of March 31, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	April 2019 - July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	98
Natural Gas	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	(14)
Natural Gas	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	(170)
Oil	April 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(499)
Oil	April 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(103)
Oil	April 2019 - June 2019	Collar	12,000	Bbls	$	70.00	-	76.25	(3)	$	350
Oil	April 2019 - July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	137
Oil	July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	138
Oil	Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	311
Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	284
		Total net fair value of derivative instruments								$	532

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on Argus Louisiana Light Sweet crude oil prices.

(3) Based on West Texas Intermediate crude oil prices.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	1,371	$	—	$	1,371
Liabilities	$	(839)	$	—	$	(839)

(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, 2018 (in thousands):

	Gross		Netting (1)		Total
Assets	$	4,600	$	—	$	4,600
Liabilities	$	(422)	$	—	$	(422)

(1)   Represents counterparty netting under agreements governing such derivatives.

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The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarters ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018
Crude oil contracts	$	655	$	(588)
Natural gas contracts		113		75
Realized gain (loss)	$	768	$	(513)
Crude oil contracts	$	(3,443)	$	(284)
Natural gas contracts		(203)		(235)
Unrealized loss	$	(3,646)	$	(519)
Loss on derivatives, net	$	(2,878)	$	(1,032)

In May 2019, the Company entered into the following additional financial derivative contracts with a third party counterparty under an unsecured line of credit with no margin call provisions:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.84	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53	(1)
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.53	(1)
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.70	(1)
Oil	May 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72	(2)
Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(2)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(2)

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on West Texas Intermediate crude oil prices.

In May 2019, the Company also entered into a costless swap agreement with a Mid-Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. 

6. Stock-Based Compensation

Restricted Stock 

During the quarter ended March 31, 2019, the Company granted 307,650 shares of restricted common stock, which vest over three years, to employees and executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2019, was $3.20 per share, with a total fair value of approximately $1.0 million and no adjustment for an estimated weighted average forfeiture rate. There were no forfeitures of restricted stock during the quarter ended March 31, 2019.  The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2019 related to restricted stock granted to its officers, employees and directors. As of March 31, 2019, an additional $1.9 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 2.0 years.  Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of March 31, 2019, assuming PSUs (as defined below) are settled at 100% of target.

During the quarter ended March 31, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2018, was $3.57 per share,  with a total fair

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value of approximately $0.8 million and no adjustment for an estimated weighted average forfeiture rate. During the quarter ended March 31, 2018,  19,668 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2018 was approximately $0.2 million.  The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2018 related to restricted stock granted to its officers, employees and directors.

Performance Stock Units

Performance stock units (“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 targeted number of PSUs stated in the agreement, 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.

During the quarter ended March 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2019,  49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $14 thousand in stock compensation expense related to PSUs during the quarter ended March 31, 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures. As of March 31, 2019, an additional $1.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.2 years. 

During the quarter ended March 31, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, which will be measured between January 1, 2018 and December 31, 2020, and were valued at a weighted average fair value of $7.69 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2018, 16,900 PSUs were forfeited by former employees.  The Company recognized approximately $0.4 million in stock compensation expense related to PSUs during the quarter ended March 31, 2018.

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 quarters ended March 31, 2019 and 2018, 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 quarters ended March 31, 2019 or 2018.

During the quarter ended March 31, 2019,  no stock options were exercised and  stock options for 12,052 shares were forfeited by former employees. During the quarter ended March 31, 2018,  no stock options were exercised or forfeited.

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7. Leases

As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. Expanded disclosures with additional qualitative and quantitative information are also required. 

ASC 842 contains several optional practical expedients upon adoption, one of which is referred to as the “package of three practical expedients”. The expedients must be taken together and allow entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Company elected to apply this practical expedient package to all of its leases upon adoption. The Company also chose to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. ASC 842 provides for a modified retrospective transition approach requiring lessees to recognize and measure leases on the balance sheet at the beginning of either the earliest period presented or as of the beginning of the period of adoption. The Company elected to apply ASC 842 as of the beginning of the period of adoption (January 1, 2019) and will not restate comparative periods. For new leases, the Company will determine if an arrangement is or contains a lease at inception. The Company has elected to combine and account for lease and non-lease contract components as a lease. Leases are included as right-of-use assets within “Other current assets” and “Other non-current assets” and a lease liability within “Accounts payable and accrued liabilities” and “Other long term liabilities” on the Company’s consolidated balance sheet.

As of January 1, 2019, the majority of the Company’s operating leases were for field equipment, such as compressors. The adoption of ASC 842 did not have a material effect on the Company’s financial results or disclosures.  Most of the Company’s compressor contracts are on a month-to-month basis, and while it is probable the contract will be renewed on a monthly basis, the compressors can be easily substituted or cancelled be either party, with minimal penalties.  Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term.  During the quarter ended March 31, 2019, the Company entered into three new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company’s consolidated balance sheet as of March 31, 2019 includes a right of use asset of $0.2 million and lease liability of $0.2 million for these new operating leases. There were no cash payments related to these new operating leases during the quarter ended March 31, 2019.

The Company's leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment.For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.

The weighted average discount rate and weighted average remaining lease term as of March 31, 2019 was 6.00% and 24.2 months, respectively.

Maturities for the Company’s operating lease liabilities on the consolidated balance sheet as of March 31, 2019, were as follows (in thousands):

		Three Months Ended March 31, 2019
2019 (remaining after March 31, 2019)	$	91
2020		101
2021		25
2022		9
Total future minimum lease payments		226
Less: imputed interest		(15)

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Present value of lease liabilities $ 211

The following table summarizes expenses related to operating leases for the three months ended March 31, 2019 (in thousands):

		Three Months Ended March 31, 2019
Operating lease cost (1) (2)	$	371
Administrative lease cost (3)		19
Short-term lease cost (1) (4)		510
Total lease cost	$	900

(1) This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners.

(2) Includes operating expense related to office lease which expired on March 31, 2019.

(3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4) Costs related primarily to rig and compressor agreements with lease terms of more than one month and less than one year.

On April 1, 2019, the Company entered into a two year extension of its office lease, which will result in an estimated $0.5 million right of use asset and lease liability to be recognized on the Company’s consolidated balance sheet for the quarter ending June 30, 2019.

8. 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):

	March 31, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	5,371	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,472		3,833
Income taxes receivable		848		424
Other receivables		121		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,530	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	256	$	792
Other		212		511
Total prepaid expenses and other	$	468	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	13,615	$	17,986
Advances from partners		2,101		1,785
Accrued exploration and development		2,531		4,751
Accrued acquisition costs		3,763		4,352
Trade payables		3,099		3,385
Accrued general and administrative expenses		2,403		2,545
Accrued operating expenses		1,229		1,801
Other accounts payable and accrued liabilities		3,447		2,901
Total accounts payable and accrued liabilities	$	32,188	$	39,506

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Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2019 and 2018 (in thousands):

		Three Months Ended March 31,
		2019		2018
Cash payments:
Interest payments	$	1,046	$	1,448
Income tax payments	$	40	$	—
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	(2,220)	$	3,669

9. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at March 31, 2019 was approximately $6.1 million. The Company’s share in Exaro’s results of operations recognized for the quarters ended March 31, 2019 and 2018 was a gain of $0.3 million, net of no tax expense, and a gain of $0.7 million, net of no tax expense, respectively.

10. Indebtedness

Credit Facility 

The Company’s $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “Credit Facility”) currently matures on October 1, 2019. The borrowing base under the facility is redetermined each November 1 and May 1. As of March 31, 2019, the borrowing base under the Credit Facility was $90 million. The Company is currently going through its regularly scheduled May redetermination process.

As of March 31, 2019, the Company had approximately $65.6 million outstanding under the Credit Facility and $1.9 million in an outstanding letter of credit. As of December 31, 2018, the Company had approximately $60.0 million outstanding under the Credit Facility and $1.9 million in outstanding letters of credit. As of March 31, 2019, borrowing availability under the Credit Facility was $22.6 million.

The Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties.

Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2019 was approximately $1.1 million. Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2018 was approximately $1.4 million.

The weighted average interest rate in effect at March 31, 2019 and December 31, 2018 was 6.2% and 6.3%, respectively. 

The Credit Facility contains restrictive covenants which, among other things, require a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Facility.  The 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, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of March 31, 2019, the Company was in compliance with all of its covenants under the Credit Facility. 

Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives

Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its existing Credit Facility, which matures on October 1, 2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures, and in

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such case there is substantial doubt that the Company could continue as a going concern. The refinancing and/or replacement of the Credit Facility could be made in conjunction with a substantial acquisition or disposition, an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended Credit Facility that would be expected to provide additional borrowing capacity for future capital expenditures. While the Company reviews such liquidity-enhancing alternative sources of capital, it intends to continue to minimize its drilling program capital expenditures in the Southern Delaware Basin and pursue a reduction in its borrowings under the Credit Facility, including through a reduction in cash general and administrative expenses and the possible sale of additional non-core properties.

11. Income Taxes

The Company’s income tax provision for continuing operations consists of the following (in thousands):

	Three Months Ended March 31,
	2019		2018
Current tax provision:
Federal	$	—	$	—
State		27		158
Total	$	27	$	158
Total tax provision:
Federal	$	—	$	—
State		27		158
Total income tax provision	$	27	$	158

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 quarter ended March 31, 2019, the Company continued to record a full valuation allowance against its net deferred tax assets. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

The Company expects that its effective income tax rate for 2019 will be less than 1% consisting entirely of state of Louisiana income taxes.

In the quarter ended December 31, 2018, the Company experienced an Ownership Change as described in Internal Revenue Code section 382 as a result of a completed follow-on equity offering. Management estimates that as a result of this Ownership Change, its future Net Operating Loss (NOL) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year, plus the amount of any built in gains (essentially: the excess of the fair market value of properties over their respective income tax bases) recognized in the five years after 2018. As a result of these limitations, it is likely that a substantial portion of the Company’s pre-2018 NOLs will expire unused. Due to the presence of the valuation allowance from prior years, this event resulted in no net charge to earnings. The Company is performing additional analysis related to this matter which will be finalized when the Company files its 2018 U.S. federal income tax return later this year.

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.

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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 appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company continues to vigorously defend this lawsuit and has filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. The Company is awaiting a response from the Texas Supreme Court as to whether it intends to review the case. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals’ ruling.

In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in the 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 appealed the trial court’s decision to the applicable state Court of Appeals. In December 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff has filed a petition requesting that the matter be reviewed by the Texas Supreme Court; the parties are awaiting a response from the Texas Supreme Court as to whether it intends to review the case. The Company continues to vigorously defend 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. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and currently forecasts it will continue to not meet the minimum throughput requirements under the agreement based upon the current commodity price market and the Company’s short term strategic drilling plans. 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 incurred fees of $0.2 million and $0.3 million during the quarters ended March 31, 2019 and 2018, respectively. As of March 31, 2019, the Company estimates that the net deficiency fee will be approximately $1.0 million for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. The Company has now accrued the total estimated remaining $2.0 million loss contingency through the expiration of the contract on March 31, 2020.

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Available Information

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”). This report should be read together with our 2018 Annual Report on Form 10-K. We are not including the information on our website as a part of, or incorporating it by reference into, this report.

Cautionary Statement about Forward-Looking Statements

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should”, “will”, “believe”, “plan”, “intend”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in our 2018 Annual Report on Form 10-K and those factors summarized below:

· our ability to continue as a going concern;

· our ability to successfully develop our undeveloped acreage in the Southern Delaware Basin and realize the benefits associated therewith;

· our financial position;

· our business strategy, including execution of any changes in our strategy;

· our ability to meet our forecasts and budgets, including our 2019 capital expenditure budget;

· expectations regarding natural gas and oil markets in the United States;

· volatility in natural gas, natural gas liquids and oil prices, including regional differentials;

· operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and natural gas processing facilities;

· the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts and explosions;

· the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which we have made a large capital commitment relative to the size of our capitalization structure;

· the timing and successful drilling and completion of natural gas and oil wells;

· our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations, and fund our drilling program;

· our ability to comply with financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness;

· the cost and availability of rigs and other materials, services and operating equipment;

· timely and full receipt of sale proceeds from the sale of our production;

· our ability to find, acquire, market, develop and produce new natural gas and oil properties;

· interest rate volatility;

· our ability to complete strategic dispositions or acquisitions of assets or businesses and realize the benefits of such dispositions or acquisitions;

· uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

· the need to take impairments on our properties due to lower commodity prices;

· the ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by the Bureau of Ocean Energy Management;

· operating hazards attendant to the natural gas and oil business including weather, environmental risks, accidental spills, blowouts and pipeline ruptures, and other risks;

· downhole drilling and completion risks that are generally not recoverable from third parties or insurance;

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· potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps;

· actions or inactions of third-party operators of our properties;

· actions or inactions of third-party operators of pipelines or processing facilities;

· the ability to retain key members of senior management and key technical employees and to find and retain skilled personnel;

· strength and financial resources of competitors;

· federal and state legislative and regulatory developments and approvals (including additional taxes and changes in environmental regulations);

· worldwide economic conditions;

· the ability to construct and operate infrastructure, including pipeline and production facilities;

· the continued compliance by us with various pipeline and gas processing plant specifications for the gas and condensate produced by us;

· operating costs, production rates and ultimate reserve recoveries of our natural gas and oil discoveries;

· expanded rigorous monitoring and testing requirements;

· the ability to obtain adequate insurance coverage on commercially reasonable terms; and

· the limited trading volume of our common stock and general market volatility.

Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.

We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and in our 2018 Form 10-K, previously filed with the Securities and Exchange Commission ("SEC").

Overview

We are a Houston, Texas based, independent oil and natural gas company. Our business is to maximize production and cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas and Wyoming properties and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States.

The following table lists our primary producing areas as of March 31, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp
Madison and Grimes counties, Texas	Woodbine (Upper Lewisville)
Zavala and Dimmit counties, Texas	Buda / Eagle Ford / Georgetown
San Augustine County, Texas	Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast	Conventional and smaller unconventional formations
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 our reported production results for all periods shown in this report.

Capital Expenditures

Our 2019 capital program has focused, and will continue to focus, on the development of our 17,700 gross operated (8,200 total net) acres in our Southern Delaware Basin acreage in Pecos County, Texas. Until a sustained improvement in commodity prices occurs, we will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand our presence in those existing areas. Despite challenges experienced throughout the Southern Delaware Basin related to constrained production takeaway capacity, and the adverse impact on commodity price differentials, we still generate positive returns to date on our drilling investment. We continuously monitor the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, will make adjustments to our capital program as the year progresses.

Additionally, we will continue to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which we can leverage our geological and operational experience and expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to economically grow production and add reserves.

Southern Delaware Basin  (West Texas)

As of December 31, 2018, we had nine wells producing from the Wolfcamp A, three wells producing from the Wolfcamp B, and a fourth well drilled in the Wolfcamp B that will be completed later in 2019. 

On March 19, 2019, we spud the Iron Snake #1H, targeting the Wolfcamp B formation. This well was drilled to a total measured depth of 20,511 feet, including a 10,112 foot lateral. Due to infrastructure required to be built in this portion of our acreage, completion operations are expected to begin in August 2019, with first production expected in October 2019. 

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On April 24, 2019, we spud the American Hornet #1H, targeting the Wolfcamp A formation. This well is expected to be drilled to a total measured depth of approximately 20,100 feet, including a 10,000 foot lateral, with production expected to begin in September 2019. For the remainder of the year, our capital expenditure budget calls for us to drill two more wells and complete a total of five wells, with the next well to be the Breakthrough State #1H. This well will target the Wolfcamp A formation and is expected to be spud in May 2019. 

Impairment of Long-Lived Assets

We recognized no impairment of proved properties during the quarter ended March 31, 2019. Under GAAP, an impairment charge is required when the unamortized capital cost of any individual property within the Company’s producing property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves for that property. We recognized impairment expense of approximately $0.5 million for the quarter ended March 31, 2019, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Going Concern Assessment

As discussed below under “Capital Resources and Liquidity”, our Credit Facility (as defined in “Capital Resources and Liquidity”) currently matures on October 1, 2019. Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our existing Credit Facility. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about our ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming we will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should we be unable to continue as a going concern. As discussed below under “Capital Resources and Liquidity,” management is evaluating plans to refinance and/or replace the Credit Facility.

Summary Production Information

Our production for the quarter ended March 31, 2019 was approximately 65% offshore and 35% onshore, volumetrically, and was comprised of 59% natural gas, 23% oil and 18% natural gas liquids. Our production for the three months ended March 31, 2018 was 64% offshore and 36% onshore, volumetrically, and was comprised of approximately 65% natural gas, 19% oil and 16% natural gas liquids.

The table below sets forth our average net daily production data in Mmcfe/d for each of our fields for each of the periods indicated:

	Three Months Ended
	March 31, 2018	June 30, 2018	September 30, 2018	December 31, 2018	March 31, 2019
Offshore (1)	32.0	23.7	27.2	25.3	23.5
West Texas	4.5	6.7	6.4	7.5	5.9
Other Onshore (2)	13.5	12.0	10.0	7.0	6.5
	50.0	42.4	43.6	39.8	35.9

(1) Includes a decreased production rate of 4.2 Mmcfe/d due to downtime related to compressor installation and maintenance during the three months ended June 30, 2018 and a decreased production rate of 0.5 Mmcfe/d due to temporary pipeline limitations during the three months ended December 31, 2018. Our Vermilion 170 well was sold effective December 1, 2018 and produced at an average daily rate of 2.2 Mmcfe/d during 2018. Our GOM production was not materially affected by Hurricane Michael which passed through the northeastern GOM in October 2018.

(2) Includes Woodbine production from Madison and Grimes counties and conventional production in others; Eagle Ford and Buda production from Zavala and Dimmit counties; and wells in East Texas and Wyoming. Decrease in production during three months ended December 31, 2018 is primarily due to the Liberty and Hardin County property sale in November 2018.

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Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, owns a  37% ownership interest in Exaro. As of March 31, 2019, Exaro had 648 wells on production over its 5,760 gross acres (1,040 net), with a working interest between 2.4% and 32.5%. These wells were producing at a rate of approximately 19 Mmcfe/d, net to Exaro. As a result of our investment in Exaro, we recognized an investment gain of approximately $0.3 million, net of no tax expense, and an investment gain of $0.7 million, net of no tax expense, for the quarters ended March 31, 2019 and 2018, respectively. See Note 9 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.

Non-Core Asset Sales

As we have expanded our presence in the Southern Delaware Basin, we also began to sell non-core assets to enhance our liquidity, eliminate marginal assets and reduce administrative costs by focusing our efforts on West Texas. These asset sales provide some immediate liquidity and improve our balance sheet by removing potential asset retirement obligations. During the year ended 2018, we sold certain Eagle Ford Shale assets in Karnes County, Texas for $21.0 million; Gulf Coast conventional assets in Southeast Texas for $6.0 million, and Gulf Coast conventional and unconventional assets in South Texas for $0.9 million. In December 2018, we also sold our offshore Vermilion 170 property in exchange for a retained overriding royalty interest (“ORRI”) in the well, the buyer’s assumption of the plugging and abandonment obligation and an ORRI in any future wells drilled by the buyer on two nearby prospects that would produce through this platform.

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Results of Operations for the Quarters ended March 31, 2019 and 2018

The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from operations for the quarters ended March 31, 2019 and 2018. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported operating expenses include production taxes, such as ad valorem and severance taxes.

	Three Months Ended March 31,
	2019		2018		%
Revenues (thousands):
Oil and condensate sales	$	6,406	$	8,811	(27)	%
Natural gas sales		5,642		8,609	(34)	%
NGL sales		1,963		3,017	(35)	%
Total revenues	$	14,011	$	20,437	(31)	%
Production:
Oil and condensate (thousand barrels)
Offshore GOM		13		19	(32)	%
West Texas		64		52	24	%
Other Onshore		48		69	(30)	%
Total oil and condensate		125		140	(11)	%
Natural gas (million cubic feet)
Offshore GOM		1,635		2,296	(29)	%
West Texas		64		46	39	%
Other Onshore		194		571	(66)	%
Total natural gas		1,893		2,913	(35)	%
Natural gas liquids (thousand barrels)
Offshore GOM		66		78	(15)	%
West Texas		14		7	100	%
Other		18		40	(55)	%
Total natural gas liquids		98		125	(22)	%
Total (million cubic feet equivalent)
Offshore GOM		2,111		2,877	(27)	%
West Texas		534		402	33	%
Other Onshore		590		1,225	(52)	%
Total production		3,235		4,504	(28)	%
Daily Production:
Oil and condensate (thousand barrels per day)
Offshore GOM		0.1		0.2	(32)	%
West Texas		0.7		0.6	24	%
Other Onshore		0.6		0.8	(30)	%
Total oil and condensate		1.4		1.6	(11)	%
Natural gas (million cubic feet per day)
Offshore GOM		18.2		25.5	(29)	%
West Texas		0.7		0.5	39	%
Other Onshore		2.1		6.4	(66)	%
Total natural gas		21.0		32.4	(35)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM		0.7		0.9	(15)	%
West Texas		0.2		0.1	100	%
Other		0.2		0.4	(55)	%
Total natural gas liquids		1.1		1.4	(22)	%

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	Three Months Ended March 31,
	2019		2018		%
Total (million cubic feet equivalent per day)
Offshore GOM		23.5		32.0	(27)	%
West Texas		5.9		4.5	33	%
Other Onshore		6.5		13.5	(52)	%
Total production		35.9		50.0	(28)	%
Average Sales Price:
Oil and condensate (per barrel)	$	51.08	$	62.76	(19)	%
Natural gas (per thousand cubic feet)	$	2.98	$	2.96	1	%
Natural gas liquids (per barrel)	$	19.96	$	23.97	(17)	%
Total (per thousand cubic feet equivalent)	$	4.33	$	4.53	(4)	%
Expenses (thousands):
Operating expenses	$	5,192	$	6,927	(25)	%
Exploration expenses	$	224	$	469	(52)	%
Depreciation, depletion and amortization	$	7,556	$	10,485	(28)	%
Impairment and abandonment of oil and gas properties	$	587	$	3,327	(82)	%
General and administrative expenses	$	5,005	$	6,726	(26)	%
Gain from investment in affiliates (net of taxes)	$	30	$	707	(96)	%
Selected data per Mcfe:
Operating expenses	$	1.60	$	1.54	4	%
General and administrative expenses	$	1.55	$	1.49	4	%
Depreciation, depletion and amortization	$	2.34	$	2.33	—	%

* Greater than 1,000%

Quarter Ended March 31, 2019 Compared to Quarter Ended March 31, 2018

Natural Gas, Oil and NGL Sales and Production

All of our revenues are from the sale of our natural gas, oil and NGL production. Our revenues may vary significantly from year to year depending on production volumes and changes in commodity prices, each of which may fluctuate widely. Our production volumes are subject to significant variation as a result of new operations, weather events, transportation and processing constraints and mechanical issues. In addition, our production naturally declines over time as we produce our reserves.

We reported revenues of $14.0 million for the quarter ended March 31, 2019, compared to revenues of $20.4 million for the quarter ended March 31, 2018.  The decrease in revenues was primarily attributable to lower natural gas production, which was primarily related to non-core property sales and the expected year over year decline in our offshore properties, as well as lower crude oil prices during the quarter ended March 31, 2019.

Total equivalent production was 35.9 Mmcfe/d for the quarter ended March 31, 2019, compared to 50.0 Mmcfe/d in the prior year quarter. Net natural gas production for the quarter ended March 31, 2019 was approximately 21.0 Mmcf/d, compared with approximately 32.4 Mmcf/d for the quarter ended March 31, 2018, of which approximately half of the decline was related to non-core property sales, and the remainder to normal field decline in our offshore properties. Net oil production decreased from approximately 1,600 barrels per day to 1,400 barrels per day, and NGL production decreased from approximately 1,400 barrels per day to 1,100 barrels per day. The higher-unit value oil and NGL production (but lower volume equivalency than gas) increased from 35% to 41% of total production due to the success of our oil-weighted West Texas drilling program. West Texas accounted for 17% of total equivalent production for the quarter ended March 31, 2019, as compared to 9% of total equivalent production for the quarter ended March 31, 2018. 

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Average Sales Prices

The average equivalent sales price realized for the quarter ended March 31, 2019 was $4.33 per Mcfe compared to $4.53 per Mcfe for the quarter ended March 31, 2018. This decrease was attributable primarily to the decrease in the realized price of oil to $51.08 per barrel, compared to $62.76 per barrel for the quarter ended March 31, 2018, and to the decrease in the realized price of NGLs to $19.96 per barrel, compared to $23.97 per barrel for the quarter ended March 31, 2018. 

Operating Expenses

Operating expenses for the quarter ended March 31, 2019 were approximately $5.2 million, or $1.60 per Mcfe, compared to $6.9 million, or $1.54 per Mcfe, for the quarter ended March 31, 2018. The table below provides additional detail of operating expenses for the three month periods:

	Three Months Ended March 31,
	2019			2018
	(in thousands)		(per Mcfe)	(inthousands)		(per Mcfe)
Lease operating expenses	$	3,685	$ 1.14	$	5,044	$ 1.12
Production & ad valorem taxes		386	0.12		782	0.17
Transportation & processing costs		695	0.21		597	0.13
Workover costs		426	0.13		504	0.12
Total operating expenses	$	5,192	1.60	$	6,927	$ 1.54

Lease operating expenses decreased from $5.0 million during the quarter ended March 31, 2018 to $3.7 million for the quarter ended March 31, 2019, primarily due to non-core property sales.

Production and ad valorem expenses decreased from $0.8 million during the quarter ended March 31, 2018 to $0.4 million for the quarter ended March 31, 2019 primarily as a result of lower production associated with our non-core property sales.

Impairment Expenses

No impairment of proved properties was recognized for the quarter ended March 31, 2019, compared to $2.3 million in non-cash proved property charges for the quarter ended March 31, 2018, related to the Vermilion 170 offshore property, which was subsequently sold on December 1, 2018. During the quarters ended March 31, 2019 and 2018, we recognized non-cash impairment expense of approximately $0.5 million and approximately $0.8 million, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the quarter ended March 31, 2019 was approximately $7.6 million, or $2.34 per Mcfe. This compares to approximately $10.5 million, or $2.33 per Mcfe, for the quarter ended March 31, 2018. The lower depletion expense for the three months ended March 31, 2019 was attributable primarily to lower production.

General and Administrative Expenses

Total general and administrative expenses for the quarter ended March 31, 2019 were approximately $5.0 million, compared to $6.7 million for the quarter ended March 31, 2018. The decrease in general and administrative expenses primarily relates to $1.9 million in lower salaries and bonus payouts during the current quarter. Exclusive of non-cash stock-based compensation, general and administrative expenses for the quarter ended March 31, 2019 were approximately $4.0 million, compared to $5.3 million for the quarter ended March 31, 2018.

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Gain (Loss) from Affiliates

For the quarters ended March 31, 2019 and March 31, 2018, we recorded a gain from affiliates of approximately $0.3 million, net of no tax expense, and a gain of $0.7 million, net of no tax expense, respectively, related to our investment in Exaro.

Gain (Loss) from Sale of Assets

During the quarter ended March 31, 2019, we recorded a loss on sale of assets of $12 thousand primarily related to final closing adjustments from sales of non-core properties during 2018. During the quarter ended March 31, 2018 we recorded a gain on sale of assets of $9.4 million, prior to final closing adjustments, related to the sale of our operated Eagle Ford Shale assets located in Karnes County, Texas.

Capital Resources and Liquidity

During the quarter ended March 31, 2019, we incurred expenditures of $2.8 million on capital projects, including $0.9 million for the commencement of our drilling program in the Southern Delaware Basin and $0.6 million in leasehold acquisition costs in the Southern Delaware Basin. We also incurred $0.6 million for the drilling and completion of two non-operated wells targeting the Georgetown formation in our Other Onshore area. The remaining incurred expenditures are primarily related to workovers.

Our capital expenditure budget for 2019 remains at an estimated $30.3 million. The budget includes $6.8 million in leasehold and infrastructure costs and $21.6 million in drilling costs of up to four wells and completion costs of up to five wells in the Southern Delaware Basin. The budget also includes $1.9 million in drilling and completion costs for the two above referenced non-operated wells. If we are able to refinance and/or replace our Credit Facility, we believe that our internally generated cash flow and proceeds from the sale of non-core assets, combined with availability under our Credit Facility will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve months.  If we are not able to refinance and/or replace our Credit Facility, there is substantial doubt about our ability to continue as a going concern. See “Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives”.

Cash From Operating Activities

Cash flows used in operating activities were approximately $0.1 million in cash for the quarter ended March 31, 2019 compared to $2.1 million provided by operating activities for the same period in 2018. The table below provides additional detail of cash flows from operating activities for the quarters ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
	(inthousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	4,525	$	6,308
Changes in operating assets and liabilities		(4,664)		(4,239)
Net cash provided by (used in) operating activities	$	(139)	$	2,069

Cash From Investing Activities

Net cash flows used in investing activities were $5.1 million for the quarter ended March 31, 2019, substantially all of which was related to cash capital costs for leasehold and drilling costs of wells in the Southern Delaware Basin and non-operated wells in the Georgetown formation.

Net cash flows provided by investing activities were $4.7 million for the quarter ended March 31, 2018, as proceeds from asset sales exceeded cash capital costs. We expended $16.2 million in cash capital costs, primarily related to drilling and/or completing wells in the Southern Delaware Basin and acquiring or extending unproved leases during the quarter, offset by $21.0 million provided by the sale of our properties in Karnes County, Texas.

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Cash From Financing Activities

Cash flows provided by financing activities for the quarter ended March 31, 2019 were approximately $5.3 million, primarily related to net borrowings outstanding under our Credit Facility. Cash flows used in financing activities for the quarter ended March 31, 2018 were approximately $6.8 million, primarily related to net repayment of borrowings outstanding under our Credit Facility.

Credit Facility

Our $500 million secured revolving credit facility with Royal Bank of Canada and other lenders (the “Credit Facility”), currently matures October 1, 2019. The borrowing base under the facility is redetermined each November and May. As of March 31, 2019, the borrowing base under the Credit Facility was $90 million, with $22.6 million available for borrowings. We are currently going through our regularly scheduled May redetermination process. Our redetermination process may result in a reaffirmation of the borrowing base or a material reduction in the borrowing base. Any reduction would further reduce our access to capital to finance operations and growth. Amounts borrowed in excess of any lowered borrowing base would be due and payable within a six month period.

The Credit Facility contains restrictive covenants which, among other things, require a Current Ratio of greater than or equal to 1.00  and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Facility. The 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, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants including the current ratio covenant, bankruptcy, insolvency or change of control events. As of March 31, 2019, we were in compliance with all of our covenants under the Credit Facility.

Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives

Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our existing Credit Facility, which matures on October 1, 2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about our ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming we will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should we be unable to continue as a going concern.

The refinancing and/or replacement of the Credit Facility could be made in conjunction with a substantial acquisition or disposition, an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended Credit Facility that would be expected to provide additional borrowing capacity for future capital expenditures. While we review such liquidity-enhancing alternative sources of capital, we intend to continue to minimize our drilling program capital expenditures in the Southern Delaware Basin and pursue a reduction in our borrowings under the Credit Facility, including through a reduction in cash general and administrative expenses and the possible sale of additional non-core properties. 

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our 2018 Form 10-K.

31

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to our Financial Statements – “Summary of Significant Accounting Policies.”

Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of March 31, 2019, we have no off-balance sheet arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.   

Item 3.Quantitative and Qualitative Disclosures About Market Risk

As a “smaller reporting company”, we are not required to provide the information required by this Item.

Item 4.Controls and Procedures

Our management, with the participation of our President and Chief Executive Officer and our Chief Financial and Accounting Officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31, 2019. Based upon that evaluation, our President and Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of March 31, 2019, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer and our Chief Financial and Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.Legal Proceedings

For a discussion of legal proceedings, see Note 12 to our Financial Statements – “Commitments and Contingencies.”

Item 1A.Risk Factors   

There have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2018.

32

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

The Company withheld the following shares from employees during the quarter ended March 31, 2019 for the payment of taxes due on shares of restricted stock that vested and were issued under its stock-based compensation plans:

				Total Number of Shares		Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part of		of Shares that May Yet
Period	Shares Withheld	Per Share		Publicly Announced Program		be Purchased Under Program
January 2019	-	$	-	—	$	—
February 2019	39,490	$	3.85	—	$	—
March 2019	9,925	$	3.43	—	$	—
Total	49,415	$	3.77	—	$	31.8 million (1)

(1) In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. The program does not have an expiration date. Pursuant to the sixth amendment to the Company’s Credit Facility,  share repurchases under this plan have been suspended.  

Item 3.Defaults upon Senior Securities

None.

Item 4.Mine Safety Disclosures

Not applicable.

Item 5.Other Information   

None.

33

Item 6.Exhibits

Exhibit Number	Description
3.1	Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000 and incorporated by reference herein).
3.2	Amendment to the Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-QSB for the quarter ended September 30, 2002, as filed with the Securities and Exchange Commission on November 14, 2002 and incorporated by reference herein).
3.3	Third Amended and Restated Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on March 3, 2015 and incorporated by reference herein).
3.4	Certificate of Designations of Series A Junior Participating Preferred Stock of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s Report on Form 8-K dated August 1, 2018, as filed with the Securities and Exchange Commission on August 2, 2018 and incorporated by reference herein).
3.5	Certificate of Elimination of Series A Junior Participating Preferred Stock of Contango Oil & Gas Company, as filed with the Secretary of the State of Delaware on March 14, 2019 (filed as Exhibit 3.5 to the Company’s Report on Form 10-K for the fiscal year ended December 31, 2018, as filed with the Securities and Exchange Commission on March 18, 2019 and incorporated by reference herein).
10.1	Separation Agreement and General Release by Contango Oil & Gas Company and Jay S. Mengle dated March 25, 2019 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 25, 2019, as filed with the Securities and Exchange Commission on March 26, 2019 and incorporated by reference herein).
31.1	Certification of Chief Executive Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
31.2	Certification of Chief Financial Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
101	Interactive Data Files †

†Filed herewith.

*     Furnished herewith.

34

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized.

		CONTANGO OIL & GAS COMPANY
Date: May 8, 2019	By:	/s/  WILKIE S. COLYER
		Wilkie S. Colyer
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: May 8, 2019	By:	/s/  E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

35

EX-31.1

Exhibit 31.1

CONTANGO OIL & GAS COMPANY

Certification Required by Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

I, Wilkie S. Colyer, President and Chief Executive Officer of Contango Oil & Gas Company (the “Company”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: May 8, 2019	By:	/S/    WILKIE. S. COLYER
		Wilkie S. Colyer President and Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CONTANGO OIL & GAS COMPANY

Certification Required by Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

I, E. Joseph Grady, Chief Financial and Accounting Officer of Contango Oil & Gas Company (the “Company”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: May 8, 2019	By:	/S/    E. JOSEPH GRADY
		E. Joseph Grady Senior Vice President and Chief Financial and Accounting Officer (Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

CONTANGO OIL & GAS COMPANY

 CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Contango Oil & Gas Company (the “Company”) on Form 10-Q for the quarter ended March 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Wilkie S. Colyer, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 8, 2019	By:	/S/    WILKIE S. COLYER
		Wilkie S. Colyer President and Chief Executive Officer (Principal Executive Officer)

EX-32.2

Exhibit 32.2

CONTANGO OIL & GAS COMPANY

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Contango Oil & Gas Company (the “Company”) on Form 10-Q for the quarter ended March 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, E. Joseph Grady, Chief Financial and Accounting Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 8, 2019	By:	/S/    E. JOSEPH GRADY
		E. Joseph Grady Senior Vice President and Chief Financial and Accounting Officer (Principal Financial and Accounting Officer)

XML

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 03, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Registrant Name	Contango Oil & Gas Company
Entity Central Index Key	0001071993
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		34,400,594
Entity Current Reporting Status	Yes
Entity Small Business	true
Entity Emerging Growth Company	false

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net	11,530	11,531
Prepaid expenses	468	1,303
Current derivative asset	1,371	4,600
Other current assets	112
Total current assets	13,481	17,434
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	1,096,714	1,095,417
Unproved properties	35,538	34,612
Other property and equipment	1,331	1,314
Accumulated depreciation, depletion and amortization	(905,437)	(898,169)
Total property, plant and equipment, net	228,146	233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates	6,053	5,743
Deferred tax asset		424
Other	352	357
Total other non-current assets	6,405	6,524
TOTAL ASSETS	248,032	257,132
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	32,188	39,506
Current derivative liability	839	422
Current asset retirement obligations	1,373	1,329
Current portion of long-term debt	65,552	60,000
Total current liabilities	99,952	101,257
NON-CURRENT LIABILITIES:
Asset retirement obligations	12,108	12,168
Other long term liabilities	3,421	3,318
Total non-current liabilities	15,529	15,486
Total liabilities	115,481	116,743
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 39,925,092 shares issued and 34,416,727 shares outstanding at March 31, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018	1,585	1,573
Additional paid-in capital	340,935	339,981
Treasury shares at cost (5,508,365 shares at March 31, 2019 and 5,458,950 shares at December 31, 2018)	(129,216)	(129,030)
Retained earnings (deficit)	(80,753)	(72,135)
Total shareholders’ equity	132,551	140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 248,032	$ 257,132

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
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	39,925,092	39,617,442
Common stock, shares outstanding	34,416,727	34,158,492
Treasury stock, shares	5,508,365	5,458,950

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
REVENUES:
Revenues	$ 14,011	$ 20,437
EXPENSES:
Operating expenses	5,192	6,927
Exploration expenses	224	469
Depreciation, depletion and amortization	7,556	10,485
Impairment and abandonment of oil and gas properties	587	3,327
General and administrative expenses	5,005	6,726
Total expenses	18,564	27,934
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)	30	707
Gain (loss) from sale of assets and return on investments	(12)	9,447
Interest expense	(1,092)	(1,409)
Loss on derivatives, net	(2,878)	(1,032)
Other income (expense)	(86)	879
Total other income (expense)	(4,038)	8,592
NET INCOME (LOSS) BEFORE INCOME TAXES	(8,591)	1,095
Income tax provision	(27)	(158)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ (8,618)	$ 937
NET INCOME (LOSS) PER SHARE:
Basic (in dollars per share)	$ (0.26)	$ 0.04
Diluted (in dollars per share)	$ (0.26)	$ 0.04
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic (in shares)	33,770	24,793
Diluted (in shares)	33,770	24,841
Oil and Condensate [Member]
REVENUES:
Revenues	$ 6,406	$ 8,811
Natural Gas, Production [Member]
REVENUES:
Revenues	5,642	8,609
Natural gas liquids [Member]
REVENUES:
Revenues	$ 1,963	$ 3,017

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (8,618)	$ 937
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7,556	10,485
Impairment of natural gas and oil properties	483	3,097
Deferred income taxes	424
Loss (gain) on sale of assets	12	(9,447)
Loss (gain) from investment in affiliates	(30)	(707)
Stock-based compensation	1,052	1,424
Unrealized loss on derivative instruments	3,646	519
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other	146	(642)
Decrease (increase) in prepaid expenses	835	940
Increase (decrease) in accounts payable & advances from joint owners	(4,299)	(6,053)
Decrease in other accrued liabilities	(826)	(1,921)
Decrease in income taxes receivable, net	(424)
Increase in income taxes payable, net	27	158
Other	(123)	3,279
Net cash provided by (used in) operating activities	(139)	2,069
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(5,124)	(16,244)
Additions to furniture & equipment	(17)
Sale of oil & gas properties		20,965
Net cash provided by (used in) investing activities	(5,141)	4,721
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Facility	37,025	74,832
Repayments under Credit Facility	(31,473)	(81,551)
Net costs from equity offering	(86)
Purchase of treasury stock	(186)	(71)
Net cash provided by (used in) financing activities	5,280	(6,790)
NET CHANGE IN CASH AND CASH EQUIVALENTS	0	0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	0	0
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 0	$ 0

XML

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2017	$ 1,223	$ 302,527	$ (128,583)	$ 49,433	$ 224,600
Balance, shares at Dec. 31, 2017	25,505,715
Treasury shares at cost			(71)		(71)
Treasury shares at cost, shares	(16,032)
Restricted shares activity	$ 8	(8)
Restricted shares activity, shares	206,114
Stock-based compensation		1,424			1,424
Net income (loss)				937	937
Balance at Mar. 31, 2018	$ 1,231	303,943	(128,654)	50,370	226,890
Balance, shares at Mar. 31, 2018	25,695,797
Balance at Dec. 31, 2018	$ 1,573	339,981	(129,030)	(72,135)	$ 140,389
Balance, shares at Dec. 31, 2018	34,158,492				34,158,492
Equity offering costs		(86)			$ (86)
Treasury shares at cost			(186)		(186)
Treasury shares at cost, shares	(49,415)
Restricted shares activity	$ 12	(12)
Restricted shares activity, shares	307,650
Stock-based compensation		1,052			1,052
Net income (loss)				(8,618)	(8,618)
Balance at Mar. 31, 2019	$ 1,585	$ 340,935	$ (129,216)	$ (80,753)	$ 132,551
Balance, shares at Mar. 31, 2019	34,416,727				34,416,727

XML

Organization and Business

3 Months Ended

Mar. 31, 2019

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, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States.

The following table lists the Company’s primary producing areas as of March 31, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp
Madison and Grimes counties, Texas	Woodbine (Upper Lewisville)
Zavala and Dimmit counties, Texas	Buda / Eagle Ford / Georgetown
San Augustine County, Texas	Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast	Conventional and smaller unconventional formations
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 all periods shown in this report.

The Company has recently been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas, which is expected to continue to generate positive returns on its drilling investment in the current price environment. As of March 31, 2019, the Company was producing from twelve wells over its 17,700 gross operated (8,200 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

The Company currently expects this acreage in West Texas to be the primary focus of its drilling program for 2019. Until a sustained improvement in commodity prices occurs, the Company will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas. The Company will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales.  Throughout all this, the Company will continue to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves.

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2019

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, 2018 (the “2018 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2018 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 2018 Form 10-K. These unaudited interim consolidated results of operations for the quarter ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019.

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 the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations.

Liquidity and Going Concern

Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its Credit Facility (as defined in Note 10 – “Indebtedness”), which matures on October 1, 2019. The refinancing or replacement of the Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment 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, probable and possible 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. No impairment of proved properties was recognized during the quarter ended March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018.

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 impairment expense of approximately $0.5 million and approximately $0.8 million for quarters ended March 31, 2019 and 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Income (Loss) Per Common Share 

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (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 quarter ended March 31, 2019, the Company excluded 526,309 shares or units of potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2018, the Company excluded 670,210 shares or units of potentially dilutive securities, 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. 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.

Revenue Recognition

Adoption of ASC 606

As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

Revenue from Contracts with Customers

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. 

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606.

Transaction Price Allocated to Remaining Performance Obligations

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required.

Contract Balances

The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process.

Impact of Adoption of ASC 606

The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the quarter ended March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

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Acquisitions and Dispositions

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Acquisitions and Dispositions

3. Acquisitions and Dispositions  

On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.4 million, prior to final closing adjustments.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2019

Fair Value Measurements [Abstract]

Fair Value Measurements

4. Fair Value Measurements

Pursuant to Accounting Standards Codification Topic 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 March 31, 2019. 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 March 31, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	1,371	$	—	$	1,371	$	—
Commodity price contracts - liabilities	$	(839)	$	—	$	(839)	$	—

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 "Loss on derivatives, net" in its 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 reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives.

As of March 31, 2019, the Company's derivative contracts were all with certain members of its Credit Facility lending group, 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 Accounting Standards Codification Topic 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 approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 - "Indebtedness" for further information.

Impairments

The Company 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, probable and possible 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.

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Derivative Instruments

3 Months Ended

Mar. 31, 2019

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 March 31, 2019, 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 Credit Facility. See Note 10 – “Indebtedness” for further information regarding the 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 “Loss on derivatives, net” on the consolidated statements of operations.

As of March 31, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	April 2019 - July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	98
Natural Gas	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	(14)
Natural Gas	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	(170)
Oil	April 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(499)
Oil	April 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(103)
Oil	April 2019 - June 2019	Collar	12,000	Bbls	$	70.00	-	76.25	(3)	$	350
Oil	April 2019 - July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	137
Oil	July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	138
Oil	Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	311
Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	284
		Total net fair value of derivative instruments								$	532

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on Argus Louisiana Light Sweet crude oil prices.

(3) Based on West Texas Intermediate crude oil prices.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	1,371	$	—	$	1,371
Liabilities	$	(839)	$	—	$	(839)

(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, 2018 (in thousands):

	Gross		Netting (1)		Total
Assets	$	4,600	$	—	$	4,600
Liabilities	$	(422)	$	—	$	(422)

(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 quarters ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018
Crude oil contracts	$	655	$	(588)
Natural gas contracts		113		75
Realized gain (loss)	$	768	$	(513)
Crude oil contracts	$	(3,443)	$	(284)
Natural gas contracts		(203)		(235)
Unrealized loss	$	(3,646)	$	(519)
Loss on derivatives, net	$	(2,878)	$	(1,032)

In May 2019, the Company entered into the following additional financial derivative contracts with a third party counterparty under an unsecured line of credit with no margin call provisions:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.84	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53	(1)
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.53	(1)
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.70	(1)
Oil	May 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72	(2)
Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(2)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(2)

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on West Texas Intermediate crude oil prices.

In May 2019, the Company also entered into a costless swap agreement with a Mid-Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. 

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2019

Stock-Based Compensation [Abstract]

Stock-Based Compensation

6. Stock-Based Compensation

Restricted Stock 

During the quarter ended March 31, 2019, the Company granted 307,650 shares of restricted common stock, which vest over three years, to employees and executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2019, was $3.20 per share, with a total fair value of approximately $1.0 million and no adjustment for an estimated weighted average forfeiture rate. There were no forfeitures of restricted stock during the quarter ended March 31, 2019. The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2019 related to restricted stock granted to its officers, employees and directors. As of March 31, 2019, an additional $1.9 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 2.0 years.  Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of March 31, 2019, assuming PSUs (as defined below) are settled at 100% of target.

During the quarter ended March 31, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2018, was $3.57 per share, with a total fair value of approximately $0.8 million and no adjustment for an estimated weighted average forfeiture rate. During the quarter ended March 31, 2018, 19,668 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2018 was approximately $0.2 million. The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2018 related to restricted stock granted to its officers, employees and directors.

Performance Stock Units

Performance stock units (“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 targeted number of PSUs stated in the agreement, 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.

During the quarter ended March 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2019,  49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $14 thousand in stock compensation expense related to PSUs during the quarter ended March 31, 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures. As of March 31, 2019, an additional $1.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.2 years. 

During the quarter ended March 31, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, which will be measured between January 1, 2018 and December 31, 2020, and were valued at a weighted average fair value of $7.69 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2018, 16,900 PSUs were forfeited by former employees.  The Company recognized approximately $0.4 million in stock compensation expense related to PSUs during the quarter ended March 31, 2018.

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 quarters ended March 31, 2019 and 2018, 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 quarters ended March 31, 2019 or 2018.

During the quarter ended March 31, 2019, no stock options were exercised and  stock options for 12,052 shares were forfeited by former employees. During the quarter ended March 31, 2018, no stock options were exercised or forfeited.

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Leases

3 Months Ended

Mar. 31, 2019

Leases

Leases

7. Leases

As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. Expanded disclosures with additional qualitative and quantitative information are also required. 

ASC 842 contains several optional practical expedients upon adoption, one of which is referred to as the “package of three practical expedients”. The expedients must be taken together and allow entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Company elected to apply this practical expedient package to all of its leases upon adoption. The Company also chose to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. ASC 842 provides for a modified retrospective transition approach requiring lessees to recognize and measure leases on the balance sheet at the beginning of either the earliest period presented or as of the beginning of the period of adoption. The Company elected to apply ASC 842 as of the beginning of the period of adoption (January 1, 2019) and will not restate comparative periods. For new leases, the Company will determine if an arrangement is or contains a lease at inception. The Company has elected to combine and account for lease and non-lease contract components as a lease. Leases are included as right-of-use assets within “Other current assets” and “Other non-current assets” and a lease liability within “Accounts payable and accrued liabilities” and “Other long term liabilities” on the Company’s consolidated balance sheet.

As of January 1, 2019, the majority of the Company’s operating leases were for field equipment, such as compressors. The adoption of ASC 842 did not have a material effect on the Company’s financial results or disclosures. Most of the Company’s compressor contracts are on a month-to-month basis, and while it is probable the contract will be renewed on a monthly basis, the compressors can be easily substituted or cancelled be either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term. During the quarter ended March 31, 2019, the Company entered into three new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company’s consolidated balance sheet as of March 31, 2019 includes a right of use asset of $0.2 million and lease liability of $0.2 million for these new operating leases. There were no cash payments related to these new operating leases during the quarter ended March 31, 2019.

The Company's leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment.For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.

The weighted average discount rate and weighted average remaining lease term as of March 31, 2019 was 6.00% and 24.2 months, respectively.

Maturities for the Company’s operating lease liabilities on the consolidated balance sheet as of March 31, 2019, were as follows (in thousands):

		Three Months Ended March 31, 2019
2019 (remaining after March 31, 2019)	$	91
2020		101
2021		25
2022		9
Total future minimum lease payments		226
Less: imputed interest		(15)
Present value of lease liabilities	$	211

The following table summarizes expenses related to operating leases for the three months ended March 31, 2019 (in thousands):

		Three Months Ended March 31, 2019
Operating lease cost (1) (2)	$	371
Administrative lease cost (3)		19
Short-term lease cost (1) (4)		510
Total lease cost	$	900

(1) This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners.

(2) Includes operating expense related to office lease which expired on March 31, 2019.

(3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4) Costs related primarily to rig and compressor agreements with lease terms of more than one month and less than one year.

On April 1, 2019, the Company entered into a two year extension of its office lease, which will result in an estimated $0.5 million right of use asset and lease liability to be recognized on the Company’s consolidated balance sheet for the quarter ending June 30, 2019.

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Other Financial Information

3 Months Ended

Mar. 31, 2019

Other Financial Information [Abstract]

Other Financial Information

8. 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):

	March 31, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	5,371	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,472		3,833
Income taxes receivable		848		424
Other receivables		121		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,530	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	256	$	792
Other		212		511
Total prepaid expenses and other	$	468	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	13,615	$	17,986
Advances from partners		2,101		1,785
Accrued exploration and development		2,531		4,751
Accrued acquisition costs		3,763		4,352
Trade payables		3,099		3,385
Accrued general and administrative expenses		2,403		2,545
Accrued operating expenses		1,229		1,801
Other accounts payable and accrued liabilities		3,447		2,901
Total accounts payable and accrued liabilities	$	32,188	$	39,506

Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2019 and 2018 (in thousands):

		Three Months Ended March 31,
		2019		2018
Cash payments:
Interest payments	$	1,046	$	1,448
Income tax payments	$	40	$	—
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	(2,220)	$	3,669

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Investment In Exaro Energy III LLC

3 Months Ended

Mar. 31, 2019

Investment In Exaro Energy III LLC [Abstract]

Investment In Exaro Energy III LLC

9. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at March 31, 2019 was approximately $6.1 million. The Company’s share in Exaro’s results of operations recognized for the quarters ended March 31, 2019 and 2018 was a gain of $0.3 million, net of no tax expense, and a gain of $0.7 million, net of no tax expense, respectively.

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Indebtedness

3 Months Ended

Mar. 31, 2019

Indebtedness

Indebtedness

10. Indebtedness

Credit Facility 

The Company’s $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “Credit Facility”) currently matures on October 1, 2019. The borrowing base under the facility is redetermined each November 1 and May 1. As of March 31, 2019, the borrowing base under the Credit Facility was $90 million. The Company is currently going through its regularly scheduled May redetermination process.

As of March 31, 2019, the Company had approximately $65.6 million outstanding under the Credit Facility and $1.9 million in an outstanding letter of credit. As of December 31, 2018, the Company had approximately $60.0 million outstanding under the Credit Facility and $1.9 million in outstanding letters of credit. As of March 31, 2019, borrowing availability under the Credit Facility was $22.6 million.

The Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties.

Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2019 was approximately $1.1 million. Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2018 was approximately $1.4 million.

The weighted average interest rate in effect at March 31, 2019 and December 31, 2018 was 6.2% and 6.3%, respectively. 

The Credit Facility contains restrictive covenants which, among other things, require a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Facility.  The 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, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of March 31, 2019, the Company was in compliance with all of its covenants under the Credit Facility. 

Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives

Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its existing Credit Facility, which matures on October 1, 2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures, and in such case there is substantial doubt that the Company could continue as a going concern. The refinancing and/or replacement of the Credit Facility could be made in conjunction with a substantial acquisition or disposition, an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended Credit Facility that would be expected to provide additional borrowing capacity for future capital expenditures. While the Company reviews such liquidity-enhancing alternative sources of capital, it intends to continue to minimize its drilling program capital expenditures in the Southern Delaware Basin and pursue a reduction in its borrowings under the Credit Facility, including through a reduction in cash general and administrative expenses and the possible sale of additional non-core properties.

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Income Taxes

3 Months Ended

Mar. 31, 2019

Income Taxes [Abstract]

Income Taxes

11. Income Taxes

The Company’s income tax provision for continuing operations consists of the following (in thousands):

	Three Months Ended March 31,
	2019		2018
Current tax provision:
Federal	$	—	$	—
State		27		158
Total	$	27	$	158
Total tax provision:
Federal	$	—	$	—
State		27		158
Total income tax provision	$	27	$	158

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 quarter ended March 31, 2019, the Company continued to record a full valuation allowance against its net deferred tax assets. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

The Company expects that its effective income tax rate for 2019 will be less than 1% consisting entirely of state of Louisiana income taxes.

In the quarter ended December 31, 2018, the Company experienced an Ownership Change as described in Internal Revenue Code section 382 as a result of a completed follow-on equity offering. Management estimates that as a result of this Ownership Change, its future Net Operating Loss (NOL) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year, plus the amount of any built in gains (essentially: the excess of the fair market value of properties over their respective income tax bases) recognized in the five years after 2018. As a result of these limitations, it is likely that a substantial portion of the Company’s pre-2018 NOLs will expire unused. Due to the presence of the valuation allowance from prior years, this event resulted in no net charge to earnings. The Company is performing additional analysis related to this matter which will be finalized when the Company files its 2018 U.S. federal income tax return later this year.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2019

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 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 appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company continues to vigorously defend this lawsuit and has filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. The Company is awaiting a response from the Texas Supreme Court as to whether it intends to review the case. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals’ ruling.

In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in the 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 appealed the trial court’s decision to the applicable state Court of Appeals. In December 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff has filed a petition requesting that the matter be reviewed by the Texas Supreme Court; the parties are awaiting a response from the Texas Supreme Court as to whether it intends to review the case. The Company continues to vigorously defend 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. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and currently forecasts it will continue to not meet the minimum throughput requirements under the agreement based upon the current commodity price market and the Company’s short term strategic drilling plans. 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 incurred fees of $0.2 million and $0.3 million during the quarters ended March 31, 2019 and 2018, respectively. As of March 31, 2019, the Company estimates that the net deficiency fee will be approximately $1.0 million for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. The Company has now accrued the total estimated remaining $2.0 million loss contingency through the expiration of the contract on March 31, 2020.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2019

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 2018 Form 10-K. These unaudited interim consolidated results of operations for the quarter ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019.

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 the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations.

Liquidity and Going Concern

Liquidity and Going Concern

Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its Credit Facility (as defined in Note 10 – “Indebtedness”), which matures on October 1, 2019. The refinancing or replacement of the Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Oil and Gas Properties - Successful Efforts

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment 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 Oil and Gas Properties

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, probable and possible 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. No impairment of proved properties was recognized during the quarter ended March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018.

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 impairment expense of approximately $0.5 million and approximately $0.8 million for quarters ended March 31, 2019 and 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Income (Loss) Per Common Share

Net Income (Loss) Per Common Share 

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (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 quarter ended March 31, 2019, the Company excluded 526,309 shares or units of potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2018, the Company excluded 670,210 shares or units of potentially dilutive securities, 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. 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.

Revenue Recognition

Revenue Recognition

Adoption of ASC 606

As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

Revenue from Contracts with Customers

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. 

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606.

Transaction Price Allocated to Remaining Performance Obligations

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required.

Contract Balances

The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process.

Impact of Adoption of ASC 606

The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the quarter ended March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2019

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 March 31, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	1,371	$	—	$	1,371	$	—
Commodity price contracts - liabilities	$	(839)	$	—	$	(839)	$	—

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2019

Schedule Of Derivative Contracts

As of March 31, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	April 2019 - July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	98
Natural Gas	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	(14)
Natural Gas	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	(170)
Oil	April 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(499)
Oil	April 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(103)
Oil	April 2019 - June 2019	Collar	12,000	Bbls	$	70.00	-	76.25	(3)	$	350
Oil	April 2019 - July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	137
Oil	July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	138
Oil	Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	311
Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	284
		Total net fair value of derivative instruments								$	532

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on Argus Louisiana Light Sweet crude oil prices.

(3) Based on West Texas Intermediate crude oil prices.

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 March 31, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	1,371	$	—	$	1,371
Liabilities	$	(839)	$	—	$	(839)

(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, 2018 (in thousands):

	Gross		Netting (1)		Total
Assets	$	4,600	$	—	$	4,600
Liabilities	$	(422)	$	—	$	(422)

(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 quarters ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018
Crude oil contracts	$	655	$	(588)
Natural gas contracts		113		75
Realized gain (loss)	$	768	$	(513)
Crude oil contracts	$	(3,443)	$	(284)
Natural gas contracts		(203)		(235)
Unrealized loss	$	(3,646)	$	(519)
Loss on derivatives, net	$	(2,878)	$	(1,032)

Subsequent Derivative Contracts [Member]

Schedule Of Derivative Contracts

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.84	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53	(1)
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.53	(1)
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.70	(1)
Oil	May 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72	(2)
Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(2)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(2)

(1) Based on Henry Hub NYMEX natural gas prices.

(2) Based on West Texas Intermediate crude oil prices.

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Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases

Summary of maturities of operating lease liabilities

Maturities for the Company’s operating lease liabilities on the consolidated balance sheet as of March 31, 2019, were as follows (in thousands):

		Three Months Ended March 31, 2019
2019 (remaining after March 31, 2019)	$	91
2020		101
2021		25
2022		9
Total future minimum lease payments		226
Less: imputed interest		(15)
Present value of lease liabilities	$	211

Summary of operating lease costs

		Three Months Ended March 31, 2019
2019 (remaining after March 31, 2019)	$	91
2020		101
2021		25
2022		9
Total future minimum lease payments		226
Less: imputed interest		(15)
Present value of lease liabilities	$	211

The following table summarizes expenses related to operating leases for the three months ended March 31, 2019 (in thousands):

		Three Months Ended March 31, 2019
Operating lease cost (1) (2)	$	371
Administrative lease cost (3)		19
Short-term lease cost (1) (4)		510
Total lease cost	$	900

(1) This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners.

(2) Includes operating expense related to office lease which expired on March 31, 2019.

(3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4) Costs related primarily to rig and compressor agreements with lease terms of more than one month and less than one year.

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Other Financial Information (Tables)

3 Months Ended

Mar. 31, 2019

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):

	March 31, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	5,371	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,472		3,833
Income taxes receivable		848		424
Other receivables		121		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,530	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	256	$	792
Other		212		511
Total prepaid expenses and other	$	468	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	13,615	$	17,986
Advances from partners		2,101		1,785
Accrued exploration and development		2,531		4,751
Accrued acquisition costs		3,763		4,352
Trade payables		3,099		3,385
Accrued general and administrative expenses		2,403		2,545
Accrued operating expenses		1,229		1,801
Other accounts payable and accrued liabilities		3,447		2,901
Total accounts payable and accrued liabilities	$	32,188	$	39,506

Schedule Of Supplemental Disclosures

Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2019 and 2018 (in thousands):

		Three Months Ended March 31,
		2019		2018
Cash payments:
Interest payments	$	1,046	$	1,448
Income tax payments	$	40	$	—
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	(2,220)	$	3,669

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2019

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 March 31,
	2019		2018
Current tax provision:
Federal	$	—	$	—
State		27		158
Total	$	27	$	158
Total tax provision:
Federal	$	—	$	—
State		27		158
Total income tax provision	$	27	$	158

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Organization and Business (Details)	3 Months Ended
	Mar. 31, 2019 a item ft
Exaro Energy III LLC [Member]
Organization and Business
Equity method investment, ownership percentage	37.00%
Bullseye
Organization and Business
Number of wells | item	12
Gross acres	17,700
Net acres	8,200
Gulf of Mexico [Member] | Maximum [Member]
Organization and Business
Water depth of operations | ft	300

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Summary of Significant Accounting Policies - Impairment and Debt (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($) item	Mar. 31, 2018 USD ($)	Dec. 31, 2018
Policies
Impairment of natural gas and oil properties	$ 483	$ 3,097
Number of subsidiaries inactive and not Subsidiary Guarantor | item	1
Restricted assets, percent of net assets			25.00%
Proved property [Member]
Policies
Impairment of natural gas and oil properties	$ 0	2,300
Unproved property [Member]
Policies
Impairment of natural gas and oil properties	$ 500	$ 800

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Summary of Significant Accounting Policies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Significant Accounting Policies [Line Items]
Cash and cash equivalents
Potentially dilutive (in shares)	526,309	670,210
Term of contract	1 year
Revenue, Practical Expedient, Initial Application and Transition, Nondisclosure of Transaction Price Allocation to Remaining Performance Obligation [true/false]	true
Minimum [Member]
Significant Accounting Policies [Line Items]
Period settlement statements are received	30 days
Maximum [Member]
Significant Accounting Policies [Line Items]
Period settlement statements are received	90 days
Exaro Energy III LLC [Member]
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	37.00%

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Acquisitions and Dispositions - Dispositions (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations [Member] - Karnes County, TX Assets [Member] $ in Millions	Mar. 28, 2018 USD ($)
Disposals
Cash purchase price	$ 21.0
Gain (loss) on sale of oil and gas property	$ 9.4

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	$ 1,371	$ 4,600
Commodity price contracts - liabilities	(839)	$ (422)
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	1,371
Commodity price contracts - liabilities	$ (839)

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Derivative Instruments (Derivative Contracts) (Details) $ in Thousands	1 Months Ended	3 Months Ended
	May 31, 2019 item $ / MMBTU $ / bbl	Mar. 31, 2019 USD ($) item $ / Mcf $ / bbl
Derivative [Line Items]
Fair Value | $		$ 532
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April To July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 98
Commodity Derivative Flow Rate | item		600,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member]
Derivative [Line Items]
Fair Value | $		$ (14)
Commodity Derivative Flow Rate | item		100,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member]
Derivative [Line Items]
Fair Value | $		$ (170)
Commodity Derivative Flow Rate | item		500,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	425,000
Price/Unit-Swap | $ / MMBTU	2.84
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	400,000
Price/Unit-Swap | $ / MMBTU	2.53
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	40,000
Price/Unit-Swap | $ / MMBTU	2.53
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	375,000
Price/Unit-Swap | $ / MMBTU	2.70
Oil [Member] | Swap [Member] | Derivative Contract Period April To July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 137
Commodity Derivative Flow Rate | item		6,000
Price/Unit-Swap		66.10
Price/Unit-Floor		66.10
Oil [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member]
Derivative [Line Items]
Fair Value | $		$ 311
Commodity Derivative Flow Rate | item		9,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member]
Derivative [Line Items]
Fair Value | $		$ 284
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 138
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period May To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	2,400
Price/Unit-Swap	61.72
Oil [Member] | Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	22,000
Price/Unit-Swap	57.74
Oil [Member] | Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	15,000
Price/Unit-Swap	57.74
Oil [Member] | Collar Options [Member] | Derivative Contract Period April To December 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ (499)
Commodity Derivative Flow Rate | item		7,000
Price/Unit-Floor		50.00
Price/Unit-Cap		58.00
Oil [Member] | Collar Options [Member] | Derivative Contract 2 Period April To December 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ (103)
Commodity Derivative Flow Rate | item		4,000
Price/Unit-Floor		52.00
Price/Unit-Cap		59.45
Oil [Member] | Collar Options [Member] | Derivative Contract Period April To June 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 350
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Floor		70.00
Price/Unit-Cap		76.25
Oil [Member] | Costless Swap [Member]
Derivative [Line Items]
Price/Unit-Swap	0.05
Oil [Member] | Costless Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	12,000
Oil [Member] | Costless Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	10,000

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Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets
Gross	$ 1,371	$ 4,600
Total	1,371	4,600
Liabilities:
Gross	(839)	(422)
Total	$ (839)	$ (422)

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Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	$ 768	$ (513)
Unrealized gain (loss)	(3,646)	(519)
Gain (loss) on derivatives, net	(2,878)	(1,032)
Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	655	(588)
Unrealized gain (loss)	(3,443)	(284)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	113	75
Unrealized gain (loss)	$ (203)	$ (235)

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Stock Based Compensation (NonOption) (Details)	3 Months Ended
	Mar. 31, 2019 USD ($) $ / shares shares	Mar. 31, 2018 USD ($) $ / shares shares
Stock-based compensation
Shares available for grant | shares	1,200,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years
Activity, shares
Granted (in shares) | shares	307,650	225,782
Canceled/Forfeited (in shares) | shares		(19,668)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 3.20	$ 3.57
Stock-based compensation
Compensation expense not yet recognized	$ 1,900,000
Compensation expense, remaining weighted average vesting period	2 years
Value of issued stock	$ 1,000,000	$ 800,000
Weighted average forfeiture rate	0	0
Value of restricted shares forfeited	$ 0	$ 200,000
Stock-based compensation expense	$ 1,000,000	$ 1,000,000
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Activity, shares
Granted (in shares) | shares	117,105	190,782
Canceled/Forfeited (in shares) | shares	(49,773)	(16,900)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 6.42	$ 7.69
Stock-based compensation
Compensation expense not yet recognized	$ 1,500,000
Compensation expense, remaining weighted average vesting period	2 years 2 months 12 days
Target (as a percent)	100.00%
Stock-based compensation expense	$ 14,000	$ 400,000
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%

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Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Option roll forward
Stock options granted in period (in shares)	0	0
Exercise of stock options, shares	0	0
Expired / Forfeited (in shares)	(12,052)	0
Stock-based compensation
Excess tax benefit from exercise/cancellation of stock options	$ 0	$ 0

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Leases (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases
Lease, Practical Expedients, Package [true false]	true
Operating lease right of use asset	$ 200
Operating lease liability	$ 211
Weighted average discount rate (as a percent)	6.00%
Weighted average remaining lease term	24 months 6 days

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Leases (Maturities) (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Leases
2019 (remaining after March 31, 2019)	$ 91
2020	101
2021	25
2022	9
Total future minimum lease payments	226
Less: imputed interest	(15)
Total	$ 211

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Leases (Costs) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases
Operating lease cost	$ 371
Administrative lease cost	19
Short-term lease cost	510
Total net lease cost	$ 900
Operating lease not yet commenced term	2 years
Right of use asset operating lease not yet commenced	$ 500
Operating leases not yet commenced	$ 500

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Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Accounts receivable:
Trade receivables	$ 5,371	$ 6,052
Receivable for Alta Resources Distribution	1,712	1,993
Joint interest billings	4,472	3,833
Income taxes receivable	848	424
Other receivables	121	223
Allowance for doubtful accounts	(994)	(994)
Total accounts receivable	11,530	11,531
Prepaid expenses and other:
Prepaid insurance	256	792
Other	212	511
Total prepaid expenses and other	468	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	13,615	17,986
Advances from partners	2,101	1,785
Accrued exploration and development	2,531	4,751
Accrued acquisition costs	3,763	4,352
Trade payables	3,099	3,385
Accrued general and administrative expenses	2,403	2,545
Accrued operating expenses	1,229	1,801
Other accounts payable and accrued liabilities	3,447	2,901
Total accounts payable and accrued liabilities	$ 32,188	$ 39,506

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Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash payments:
Interest payments	$ 1,046	$ 1,448
Income tax payments (refunds), net of cash refunds	40
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$ (2,220)	$ 3,669

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Investment in Exaro Energy III LLC (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Schedule of Equity Method Investments Financials
Gain (loss) from investment in affiliates, net of income taxes	$ 30	$ 707
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Equity method investment, ownership percentage	37.00%
Share of equity in investment	$ 6,100
Gain (loss) from investment in affiliates, net of income taxes	300	700
Tax (expense) benefit from equity investment	$ 0	$ 0

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Indebtedness (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Oct. 31, 2013 USD ($)	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Interest expense		$ 1,092	$ 1,409
RBC Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 500,000
Revolving credit facility, borrowing base		90,000
Credit facility amount outstanding		65,600		$ 60,000
Letters of credit amount outstanding		1,900		$ 1,900
Line of credit, available		22,600
Interest expense		$ 1,100	$ 1,400
Weighted average interest rate (as a percent)		6.20%		6.30%
RBC Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current ratio	1.00
RBC Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio	3.50

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Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018
Current tax provision:
State	$ 27		$ 158
Total	27		158
Total tax provision:
State	27		158
Income tax provision	$ 27		$ 158
Annual carryover limitation		$ 2,400
Built in gains carryover limitation period		5 years
Maximum [Member]
Total tax provision:
Effective tax rate (as a percent)	1.00%

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Commitments and Contingencies (Details) $ in Millions	1 Months Ended		3 Months Ended
	Sep. 30, 2012 USD ($)	Nov. 30, 2010 USD ($) site	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)
Lavaca County Case [Member]
Legal Proceedings
Number of wells involved in litigation | site		2
Damages sought by plaintiffs		$ 5.3
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%
Throughput commitment
Loss Contingency
Fees incurred			$ 0.2	$ 0.3
Estimated deficiency			1.0
Loss contingency provision accrual			$ 2.0