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 September 30, 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)

TEXAS	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)

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

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  ☒

The total number of shares of common stock, par value $0.04 per share, outstanding as of November 6,  2019 was 89,357,332. 

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2019 

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of September 30, 2019 and December 31, 2018	3
	Consolidated Statements of Operations (unaudited) for the three and nine months ended September 30, 2019 and 2018	4
	Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2019 and 2018	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the nine months ended September 30, 2019 and 2018	6
	Notes to the Consolidated Financial Statements (unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	39
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults upon Senior Securities	39
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	40

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.

2

Item 1.Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)

	September 30,		December 31,
	2019		2018
	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	2,044	$	—
Accounts receivable, net		11,118		11,531
Prepaid expenses		995		1,303
Current derivative asset		2,625		4,600
Other current assets		14,820		—
Total current assets		31,602		17,434
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		1,110,042		1,095,417
Unproved properties		42,427		34,612
Other property and equipment		1,331		1,314
Accumulated depreciation, depletion and amortization		(912,098)		(898,169)
Total property, plant and equipment, net		241,702		233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates		5,872		5,743
Long-term derivative asset		509		—
Deferred tax asset		—		424
Other non-current assets		1,962		357
Total other non-current assets		8,343		6,524
TOTAL ASSETS	$	281,647	$	257,132
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	62,744	$	39,506
Current derivative liability		24		422
Current asset retirement obligations		679		1,329
Current portion of long-term debt		—		60,000
Total current liabilities		63,447		101,257
NON-CURRENT LIABILITIES:
Long-term debt		28,100		—
Asset retirement obligations		11,636		12,168
Other long-term liabilities		3,883		3,318
Total non-current liabilities		43,619		15,486
Total liabilities		107,066		116,743
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Series A convertible preferred stock, $0.04 par value, 789,474 shares authorized, issued and outstanding at September 30, 2019		32		—
Common stock, $0.04 par value, 100 million shares authorized, 85,864,463 shares issued and outstanding at September 30, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018		3,423		1,573
Additional paid-in capital		393,723		339,981
Treasury shares at cost (No shares at September 30, 2019 and 5,458,950 shares at December 31, 2018)		—		(129,030)
Accumulated deficit		(222,597)		(72,135)
Total shareholders’ equity		174,581		140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	281,647	$	257,132

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

3

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
	(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	7,281	$	8,558	$	21,126	$	26,976
Natural gas sales		4,293		7,128		13,792		21,585
Natural gas liquids sales		973		3,822		4,402		9,832
Total revenues		12,547		19,508		39,320		58,393
EXPENSES:
Operating expenses		5,435		6,382		16,321		19,787
Exploration expenses		218		425		691		1,288
Depreciation, depletion and amortization		8,473		12,853		23,602		32,836
Impairment and abandonment of oil and gas properties		1,336		72,524		3,170		76,628
General and administrative expenses		5,879		6,724		15,340		18,804
Total expenses		21,341		98,908		59,124		149,343
OTHER INCOME (EXPENSE):
Loss from investment in affiliates, net of income taxes		(608)		(270)		(151)		(38)
Gain from sale of assets		192		498		601		11,315
Interest expense		(998)		(1,411)		(3,169)		(4,082)
Gain (loss) on derivatives, net		1,881		(1,319)		1,068		(4,961)
Other income		519		357		522		1,239
Total other income (expense)		986		(2,145)		(1,129)		3,473
NET LOSS BEFORE INCOME TAXES		(7,808)		(81,545)		(20,933)		(87,477)
Income tax benefit (provision)		(30)		21		(484)		(288)
NET LOSS	$	(7,838)	$	(81,524)	$	(21,417)	$	(87,765)
NET LOSS PER SHARE:
Basic	$	(0.19)	$	(3.26)	$	(0.59)	$	(3.52)
Diluted	$	(0.19)	$	(3.26)	$	(0.59)	$	(3.52)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		41,786		25,001		36,518		24,910
Diluted		41,786		25,001		36,518		24,910

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

4

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended
	September 30,
	2019		2018
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(21,417)	$	(87,765)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		23,602		32,836
Impairment of natural gas and oil properties		2,246		76,175
Deferred income taxes		424		—
Gain on sale of assets		(601)		(11,315)
Loss from investment in affiliates		151		38
Stock-based compensation		2,193		3,772
Unrealized loss on derivative instruments		1,068		2,551
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables		590		355
Decrease in prepaids		308		702
Increase in accounts payable & advances from joint owners		14,871		3,571
Increase in other accrued liabilities		1,211		964
Increase in income taxes receivable, net		(454)		—
Increase (decrease) in income taxes payable, net		(126)		208
Decrease (increase) in deposits and other		(14,819)		3,051
Net cash provided by operating activities	$	9,247	$	25,143
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	$	(27,309)	$	(43,223)
Additions to furniture & equipment		(17)		—
Sale of oil & gas properties		10		21,562
Sale of energy credits		—		497
Net cash used in investing activities	$	(27,316)	$	(21,164)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	137,655	$	182,319
Repayments under credit facility		(169,554)		(185,928)
Net proceeds from equity offerings		53,650		—
Purchase of treasury stock		(236)		(370)
Debt issuance costs		(1,402)		—
Net cash provided by (used in) financing activities	$	20,113	$	(3,979)
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	2,044	$	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,044	$	—

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

5

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2019

(in thousands, except number of shares)

	Series A						Additional						Total
	Preferred Stock			Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
	Shares	Amount		Shares	Amount		Capital		Stock		Deficit		Equity
				(unaudited)
Balance at December 31, 2018	—	$	—	34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering - common stock	—		—	—		—		(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
Equity offering - common stock	—		—	—		—		45		—		—		45
Treasury shares at cost	—		—	(16,133)		—		—		(50)		—		(50)
Restricted shares activity	—		—	42,249		2		(2)		—		—		—
Stock-based compensation	—		—	—		—		585		—		—		585
Net loss	—		—	—		—		—		—		(4,961)		(4,961)
Balance at June 30, 2019	—	$	—	34,442,843	$	1,587	$	341,563	$	(129,266)	$	(85,714)	$	128,170
Equity offering - preferred stock	789,474		32	—		—		7,420		—		—		7,452
Equity offering - common stock	—		—	45,922,870		2,058		44,181		—		—		46,239
Treasury shares reissuance	—		—	5,524,498		(221)		—		129,266		(129,045)		—
Restricted shares activity	—		—	(25,748)		(1)		1		—		—		—
Stock-based compensation	—		—	—		—		558		—		—		558
Net loss	—		—	—		—		—		—		(7,838)		(7,838)
Balance at September 30, 2019	789,474	$	32	85,864,463	$	3,423	$	393,723	$	—	$	(222,597)	$	174,581

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

6

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2018

(in thousands, except number of shares)

				Additional						Total
	Common Stock			Paid-in		Treasury		Retained Earnings		Shareholders’
	Shares	Amount		Capital		Stock		Accumulated (Deficit)		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
Treasury shares at cost	(33,703)		—		—		(124)		—		(124)
Restricted shares activity	77,188		4		(4)		—		—		—
Stock-based compensation	—		—		1,584		—		—		1,584
Net loss	—		—		—		—		(7,178)		(7,178)
Balance at June 30, 2018	25,739,282	$	1,235	$	305,523	$	(128,778)	$	43,192	$	221,172
Treasury shares at cost	(27,860)		—		—		(175)		—		(175)
Restricted shares activity	(127,314)		(6)		6		—		—		—
Stock-based compensation	—		—		764		—		—		764
Net loss	—		—		—		—		(81,524)		(81,524)
Balance at September 30, 2018	25,584,108	$	1,229	$	306,293	$	(128,953)	$	(38,332)	$	140,237

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

7

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 Texas and Wyoming properties and use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties across the United States. On June 14, 2019, following approval by the Company’s stockholders at the 2019 annual meeting of stockholders, the Company changed its state of incorporation from the State of Delaware to the State of Texas and increased the Company’s number of authorized shares of common stock from 50 million to 100 million. 

In September 2019, the Company entered into a purchase agreement with Will Energy Corporation (“Will Energy”) and a purchase agreement with White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed subsequent to September 30, 2019. See Note 3 – “Acquisitions and Dispositions” for more information.

Also in September 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations and terminated its previous credit agreement with Royal Bank of Canada, which had an October 1, 2019 maturity. The new revolving credit agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions on October 25 and November 1, 2019, respectively, to add two additional lenders and increase the borrowing base thereunder to $145 million.  See Note 10 – “Long-Term Debt” for more information.

The following table lists the Company’s primary producing areas as of September 30, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp A and B
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.

Since 2016, the Company has been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas, which is expected to continue to generate positive returns in the current price environment. As of September 30, 2019, the Company was producing from fourteen wells over its approximate 17,400 gross operated  (8,400 total net) acre position in this West Texas area,  prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In October 2019, the Company brought two more West Texas wells online and finished completing another West Texas well, which is expected to begin producing in mid-November 2019. Additionally, the Company is currently preparing to begin completion operations on a drilled but uncompleted well which it acquired in connection with the White Star acquisition. See Note 3 – “Acquisitions and Dispositions” for more information.

The Company currently plans to limit its near-term drilling program expenditures, in West Texas and other areas, to only those necessary to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas, or to add production and cash flow at attractive rates of return. The Company will continue to make balance sheet strength a priority in 2019 and 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.

8

On September 12, 2019, the Company completed an underwritten public offering (the “Public Offering”) of 51,447,368 shares of its common stock (of which 5,524,498 was reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the Series A Private Placement (defined below) and Public Offering were used to fund the cash portion of the purchase price for the Will Energy acquisition and to reduce borrowings under the Company’s revolving credit facility then in effect.

In conjunction with the Public Offering, also on September 12, 2019, the Company entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million. On November 1, 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock, which resulted in net proceeds of approximately $21 million (the “Series B Private Placement”). Net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star acquisition.

Each of the series A and series B preferred shares are a new class of equity interests that rank equal to the common shares with respect to dividend rights and rights upon liquidation. The preferred shares will be entitled to vote on an as-converted basis on all matters submitted to a vote of the Company’s stockholders, with voting rights of the series A preferred shares equal to 19.99% of the common shares outstanding prior to the closing of the Public Offering and the series B preferred shares voting on an as-converted basis.Each series A preferred share and series B preferred share will then automatically convert into the number of common shares the purchaser would have received if the purchaser had purchased such common shares in the Public Offering and Series B Private Placement, respectively, for the same gross proceeds (the “Conversion”) and, upon the Conversion, the outstanding preferred shares will be cancelled. As of November 1, 2019, the Company has obtained approval of, or written agreements to approve, such increase in the number of authorized shares, and the issuance of the common shares underlying the series A preferred shares, from holders of a majority of the voting power of its capital stock, and will complete that process as soon as practicably possible. 

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 (“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 interim 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 nine months ended September 30, 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.

9

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. During the nine months ended September 30, 2019, the Company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018. No impairment expense was recognized during the three months ended September 30, 2019.

During the three and nine months ended September 30, 2018, the Company recognized $72.2 million and $74.9 million in total offshore and onshore non-cash proved property impairment charges, respectively. Included in offshore proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of the Company’s Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Eugene Island 11 field. Offshore non-cash proved property impairment expense for the nine months ended September 30, 2018 included an additional $2.3 million related to the Company’s Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. The three and nine months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, substantially all of which was related to the reduction in fair value on certain of the Company’s non-core properties in Southeast Texas, as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recognized non-cash impairment expense of approximately $1.2 million and approximately $2.0 million for the three and nine months ended September 30, 2019, respectively,  related to impairment of certain unproved properties primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, also related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Loss Per Common Share 

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the

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potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and nine months ended September 30, 2019, the Company excluded 2,621,614 shares or units and 1,115,719 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. For the three and nine months ended September 30, 2018, the Company excluded 884,948 shares or units and 1,328,884 shares or units, respectively, 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 joint and several and 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 Topic 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 did not recognize 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 a  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.

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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 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 nine months ended September 30, 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.

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 $9.5 million, after final closing adjustments.

On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a gain of $1.3 million after removal of the asset retirement obligations associated with the sold properties and final closing adjustments.

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On September 11, 2018, the Company entered into a definitive agreement to divest certain of its non-core assets in Liberty and Hardin counties in Southeast Texas. As a result of the sale, the Company reduced the value of the assets to their purchase price and recorded an impairment of approximately $12.8 million during the three months ended September 30, 2018. The sale was completed on November 2, 2018 for cash proceeds of $6.0 million.

On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million after removal of the asset retirement obligations associated with the sold properties.

On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties.

On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 159,872 net acres located in North Louisiana (12,560 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,312 net acres). As of September 30, 2019, the Company paid a $1.6 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the Will Energy acquisition occurred on October 25,  2019, for a total aggregate consideration of $23 million.  Following adjustments for recent sales of non-core, non-operated Louisiana properties by Will Energy, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.75 million in cash, including the $1.6 million deposit, and 3.5 million shares of common stock.

On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 315,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. As of September 30, 2019, the Company paid a $12.5 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the White Star acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.6 million in cash, including the $12.5 million deposit. 

4. Fair Value Measurements

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. Fair value is 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). A  fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2019.  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.

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Fair value information for financial assets and liabilities was as follows as of September 30, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	3,134	$	—	$	3,134	$	—
Commodity price contracts - liabilities	$	(24)	$	—	$	(24)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in 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 September 30, 2019, the Company's derivative contracts were all with major 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 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 Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter.  See Note 10 – “Long-Term Debt” 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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5. Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts.

As of September 30, 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 Agreement or under unsecured lines of credit with non-bank counterparties. See Note 10 – “Long-Term Debt” for further information regarding the Credit Agreement.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations.

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As of September 30, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	Nov 2019 - Dec 2019	Swap	445,000	Mmbtus	$	2.62			(1)	$	180
Crude Oil	Oct 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(24)
Crude Oil	Oct 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	14
Crude Oil	Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	162
Crude Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	439
Crude Oil	Oct 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72			(3)	$	57
Crude Oil	Oct 2019 - Dec 2019	Swap	1,500	Bbls	$	57.67			(3)	$	17
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.841			(1)	$	341
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532			(1)	$	370
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.532			(1)	$	21
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.696			(1)	$	133
Crude Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74			(3)	$	720
Crude Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			(3)	$	623
Crude Oil	Jan 2020 - March 2020	Swap	2,700	Bbls	$	54.33			(3)	$	12
Crude Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33			(3)	$	20
Crude Oil	July 2020	Swap	5,500	Bbls	$	54.33			(3)	$	18
Crude Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33			(3)	$	26
Crude Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33			(3)	$	27
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.505			(1)	$	(82)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.505			(1)	$	90
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.505			(1)	$	3
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.508			(1)	$	(76)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.508			(1)	$	94
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.508			(1)	$	3
		Total net fair value of derivative instruments								$	3,188

(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.

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing crude 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. The fair value of this costless swap agreement was in a liability position of $0.1 million as of September 30, 2019.

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The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	3,134	$	—	$	3,134
Liabilities	$	(24)	$	—	$	(24)

(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 three and nine months ended September 30, 2019 and 2018 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Crude oil contracts	$	500	$	(1,136)	$	1,442	$	(2,846)
Natural gas contracts		371		57		694		436
Realized gain (loss)	$	871	$	(1,079)	$	2,136	$	(2,410)
Crude oil contracts	$	1,049	$	(152)	$	(2,029)	$	(1,747)
Natural gas contracts		(39)		(88)		961		(804)
Unrealized gain (loss)	$	1,010	$	(240)	$	(1,068)	$	(2,551)
Gain (loss) on derivatives, net	$	1,881	$	(1,319)	$	1,068	$	(4,961)

In October 2019, in conjunction with the closing of the Will Energy acquisition (see Note 3 – “Acquisitions and Dispositions” for more information), the Company acquired the following additional derivative contracts with counterparties that are certain members of its credit facility lender group:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	October 2019	Collar	40,524	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	November 2019	Collar	46,377	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	December 2019	Collar	40,524	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	Jan 2020 - March 2020	Collar	225,000	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	October 2019	Collar	186,000	Mmbtus	$	2.50	-	2.975	(1)
Natural Gas	November 2019	Collar	180,000	Mmbtus	$	2.50	-	2.975	(1)
Natural Gas	December 2019	Collar	186,000	Mmbtus	$	2.50	-	2.975	(1)
Crude Oil	Oct 2019 - Dec 2019	Collar	4,000	Bbls	$	45.00	-	81.00	(2)
Crude Oil	Jan 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00	-	65.70	(2)

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

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

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In the fourth quarter of 2019, the Company entered into the following additional derivative contracts:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Dec 2019	Swap	330,000	Mmbtus	$	2.813	(1)
Natural Gas	Dec 2019	Swap	330,000	Mmbtus	$	2.81	(1)
Natural Gas	Jan 2020 - March 2020	Swap	300,000	Mmbtus	$	2.53	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53	(1)
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.53	(1)
Natural Gas	Jan 2020 - March 2020	Swap	300,000	Mmbtus	$	2.532	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532	(1)
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.532	(1)
Natural Gas	Jan 2021 - March 2021	Swap	650,000	Mmbtus	$	2.508	(1)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	Mmbtus	$	2.508	(1)
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	Mmbtus	$	2.508	(1)
Crude Oil	Nov 2019 - Dec 2019	Swap	88,000	Bbls	$	56.80	(2)
Crude Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.70	(2)
Crude Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.70	(2)
Crude Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70	(2)
Crude Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.58	(2)
Crude Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.58	(2)
Crude Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58	(2)
Crude Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(2)
Crude Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(2)
Crude Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(2)
Crude Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(2)
Crude Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(2)
Crude Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(2)

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

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

6. Stock-Based Compensation

Restricted Stock    

During the nine months ended September 30, 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. Additionally, during the nine months ended September 30, 2019,  the Company granted 80,410 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2019, was $2.91 per share, with a total fair value of approximately $1.1 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2019,  63,909 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2019 was approximately $0.3 million. The Company recognized approximately $1.7 million in restricted stock compensation expense during the nine months ended September 30, 2019 related to restricted stock granted to its officers, employees and directors. As of September 30, 2019, an additional $1.2 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.7 years. Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2019, assuming PSUs (as defined below) are settled at 100% of target.

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During the nine months ended September 30, 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. Additionally, during the nine months ended September 30, 2018,  the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2018, was $3.76 per share, with a total fair value of approximately $1.2 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2018,  152,294 restricted shares were forfeited by former employees, of which 105,800 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2018 was approximately $1.0 million. The Company recognized approximately $3.2 million in restricted stock compensation expense during the nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 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 $0.5 million in stock compensation expense related to PSUs during the nine months ended September 30, 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 September 30, 2019, an additional $1.0 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.9 years. 

During the nine months ended September 30, 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 nine months ended September 30, 2018,  182,227 PSUs were forfeited by former employees, of which 153,127 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The Company only recognized approximately $0.6 million in stock compensation expense related to PSUs during the nine months ended September 30, 2018, primarily due to the above referenced forfeitures.

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 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

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the Black-Scholes options-pricing model. No stock options were granted during the nine months ended September 30, 2019 or 2018.

During the nine months ended September 30, 2019,  no stock options were exercised and stock options for 12,673 shares were forfeited by former employees. During the nine months ended September 30, 2018,  no stock options were exercised and stock options for 4,500 shares were forfeited by former employees.

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 determines 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.

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 by 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 nine months ended September 30, 2019, the Company entered into a new office lease and new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company also entered into a new office equipment contract, which qualifies as a finance lease, during the nine months ended September 30, 2019. These leases do not have a material impact on the Company’s consolidated financial statements.

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The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2019 (in thousands):

	September 30, 2019
Operating lease right of use asset - current (1)	$	690
Operating lease right of use asset - long-term (2)		489
Total operating lease right of use asset	$	1,179
Operating lease liability - current (3)	$	(690)
Operating lease liability - long-term (4)		(489)
Total operating lease liability	$	(1,179)
Financing lease right of use asset - current (1)	$	19
Financing lease right of use asset - long-term (2)		70
Total financing lease right of use asset	$	89
Financing lease liability - current (3)	$	(17)
Financing lease liability - long-term (4)		(74)
Financing lease liability - current	$	(91)

(1) Included in “Other current assets” on the consolidated balance sheet.

(2) Included in “Other non-current assets” on the consolidated balance sheet.

(3) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet.

(4) Included in “Other long-term liabilities” on the consolidated balance sheet.

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 table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2019:

	September 30, 2019
Weighted Average Remaining Lease Terms (in months):
Operating leases	21
Financing leases	57
Weighted Average Discount Rate:
Operating leases	5.31%
Financing leases	6.00%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2019, were as follows (in thousands):

	September 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after September 30, 2019)	$	170	$	6
2020		677		17
2021		324		18
2022		8		19
2023		-		20
2024		-		11
Total future minimum lease payments		1,179		91
Less: imputed interest		(57)		(14)
Present value of lease liabilities	$	1,122	$	77

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The following table summarizes expenses related to the Company’s leases for the three and nine months ended September 30, 2019 (in thousands):

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1) (2)	$	138	$	609
Financing lease cost		5		5
Administrative lease cost (3)		19		56
Short-term lease cost (1) (4)		781		3,359
Total lease cost	$	943	$	4,029

(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 an office lease which expired on March 31, 2019 and a new office lease which began on April 1, 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 drilling rig and compressor agreements with lease terms of more than one month and less than one year.

There were $228 thousand and $4 thousand in cash payments related to operating leases and financing leases, respectively, during the nine months ended September 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):

	September 30, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	4,463	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,005		3,833
Income taxes receivable		878		424
Other receivables		1,054		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,118	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	848	$	792
Other		147		511
Total prepaid expenses and other	$	995	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	12,704	$	17,986
Advances from partners (1)		13,657		1,785
Accrued exploration and development (1)		12,036		4,751
Accrued acquisition costs		3,763		4,352
Trade payables (1)		12,441		3,385
Accrued general and administrative expenses (2)		4,365		2,545
Accrued operating expenses		1,651		1,801
Other accounts payable and accrued liabilities		2,127		2,901
Total accounts payable and accrued liabilities	$	62,744	$	39,506

(1) Increase in 2019 primarily due to an increase in drilling and completion activity in West Texas during the three months ended September 30, 2019. The Company limited its drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 to only that which was necessary to meet leasehold drilling obligations.

(2) Includes a $2.1 million accrual related to a legal judgement determined during the three months ended September 30, 2019. See Note 12 – Commitments and Contingencies” for more information.

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Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2019 and 2018 (in thousands):

		Nine Months Ended September 30,
		2019		2018
Cash payments:
Interest payments	$	3,037	$	3,846
Income tax payments	$	668	$	81
Non-cash investing activities in the consolidated statements of cash flows:
Increase in accrued capital expenditures	$	7,284	$	2,764

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 September 30, 2019 was approximately $5.9 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results or production in those reported for the Company’s consolidated results.

The Company’s share in Exaro’s results of operations recognized for the three months ended September 30, 2019 and 2018 was a loss of $0.6 million, net of no tax expense, and a loss of $0.3 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the nine months ended September 30, 2019 and 2018 was a gain of $0.1 million, net of no tax expense, and a  loss of $38 thousand, net of no tax expense, respectively. 

10. Long-Term Debt

Credit Agreement    

On September 17, 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million.  The borrowing base is subject to semi-annual redeterminations. The next redetermination will occur on or about December 1, 2019. Beginning in 2020, the semi-annual redeterminations will occur on May 1st and November 1st of each year. The borrowing base may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The Credit Agreement matures on September 17, 2024.

On September 18, 2019, the Company repaid all obligations with borrowings under the Credit Agreement,  and terminated, its previous credit agreement with the Royal Bank of Canada (the “Credit Facility”), which had an October 1, 2019 maturity.  

As of September 30, 2019,  the Company had approximately $28.1 million outstanding under the Credit Agreement 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 an outstanding letter of credit. As of September 30, 2019, borrowing availability under the Credit Agreement was $35.0 million.

The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement.

Total interest expense under the Company’s current and previous credit agreements, including commitment fees, for the three and nine months ended September 30, 2019 was approximately $1.0 million and $3.2 million, respectively. Total interest expense under the Company’s previous credit agreement, including commitment fees, for the three and nine months ended September 30, 2018 was approximately $1.4 million and $4.1 million, respectively.

The weighted average interest rates in effect at September 30, 2019 and December 31, 2018 were 5.4% under the Credit Agreement and 6.3% under the Credit Facility, respectively.

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The Credit Agreement contains customary and typical restrictive covenants. Commencing in the quarter ending December 31, 2019, the Credit Agreement requires 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 Agreement.  

11. Income Taxes 

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Current tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total	$	30	$	(21)	$	484	$	288
Total tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total income tax provision (benefit)	$	30	$	(21)	$	484	$	288

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the nine months ended September 30, 2019, the Company continued to take a full valuation allowance against its deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

Income tax expense relates to cash income taxes paid to the State of Louisiana on properties within the state that is not shielded by existing Federal tax attributes. 

In the quarter ended December 31, 2018, the Company experienced an Ownership Change (the “2018 Ownership Change”) as described in Internal Revenue Code (“IRC”) 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. 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 and expects it to be finalized in the fourth quarter of 2019.

In the quarter ended September 30, 2019, the Company issued 51.4 million additional shares of common stock pursuant to a follow-on equity offering (see Note 1 – “Organization and Business”). The cumulative effect of this equity offering, combined with other equity issuances, could have resulted in a subsequent Ownership Change, within the meaning of the IRC section 382. Based upon the information known to date, it is anticipated that if the Company experienced a subsequent Ownership Change, the IRC section 382 limit imposed by the Ownership Change could be more limiting on the ability of the Company to recover its NOLs than the 2018 Ownership Change. More specifically, the limit imposed by the subsequent Ownership Change could cause more of the Company’s NOLs to expire unused, resulting in a net impact to the Company’s effective tax rate and reported earnings. The Company is presently pursuing avenues set out in IRS guidance that allows the Company to inquire of (and rely upon) substantial shareholders as to the nature and timing of their purchases based on reliance of  “actual knowledge” (as defined in IRS guidance) to properly assess the effect of the stock issuances on its NOL recovery. The Company expects this analysis to be completed in the fourth quarter of 2019 and will record the effect (if any) on its NOLs in that period. 

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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 decades-old poorly documented transactions. Based on prior summary judgments, the trial court 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 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. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company has engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case and is seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals ruling.

In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the plaintiff. Prior to the judgement, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgement, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgement plus fees and interest. The Company is currently preparing an appeal of that court decision.

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 net fees of $0.7 million during each of the nine months ended September 30, 2019 and 2018. As of September 30, 2019, the Company estimates that the remaining net deficiency fee will be approximately $0.5 million through the expiration of the contract on March 31, 2020, all of which is currently accrued.

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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").

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 and our subsequent filings with the SEC. 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”, “efforts”, “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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 and those factors summarized below: 

· any reduction in our borrowing base from time to time;

· 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;

· meeting our forecasts and budgets, including our 2019 capital expenditure budget;

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

· 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;

· the concentration of drilling in the Southern Delaware Basin, including lower than expected production attributable to down spacing of 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;

· 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;

· the conditions of the capital markets and our ability to access debt and equity capital markets or other non-bank sources of financing

· actions by current and potential sources of capital, including lenders;

· interest rate volatility;

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· our ability to successfully integrate the businesses, properties and assets we acquire, including those in new areas of operation;  

· 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;

· 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;

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

· the volatility of our common stock and the risk we are not able to comply with NYSE American listing standards.

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.

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 use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties across the United States. On June 14, 2019, following approval by our stockholders at the 2019 annual meeting of stockholders, we changed our state of incorporation from the State of Delaware to the State of Texas and increased our number of authorized shares of common stock from 50 million to 100 million. 

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In September 2019, we entered into a purchase agreement with Will Energy Corporation (“Will Energy”) and a purchase agreement with White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed subsequent to September 30, 2019. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information. In conjunction with the signing of the Will Energy purchase agreement, we sold $53.7 million (net proceeds) in new equity to fund the cash purchase price portion of that acquisition.  In conjunction with the closing of the White Star acquisition, we sold another $21 million (net proceeds) in new equity to fund a portion of the purchase price and related transaction expenses for that acquisition. See Item 1. Note 1 – “Organization and Business” for more information.

Also in September 2019, we entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders. In connection with the entry into the new revolving credit agreement, we repaid all obligations under and terminated our previous credit agreement with Royal Bank of Canada, which had an October 1, 2019 maturity. The new revolving credit agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million.  See Item 1. Note 10 – “Long-Term Debt” for more information.

The following table lists our primary producing areas as of September 30, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp A and B
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

During the three months ended September 30, 2019, we brought two wells online in the Southern Delaware Basin, the Ripper State #2H and the American Hornet #1H, which are located in our legacy Bullseye project area. In October 2019, we brought two more wells online, the Iron Snake #1H and the Breakthrough State #1H, which are located in our Northeast Bullseye project area (“NE Bullseye”).  These NE Bullseye wells are performing at the high end of our expected NE Bullseye range; however, we have less than one month of production. NE Bullseye is a more productive and higher oil cut area and will be the primary focus of future capital spending in the area to the extent we decide to drill additional wells. Both Bullseye wells were boundary delineation wells drilling in the Southeast and Southwest boundaries of the acreage, and both wells are performing at the low end of the expected Bullseye performance range. 

In addition, we have recently finished completing the Old Ironside #1H in NE Bullseye and expect to begin production of that well in mid-November 2019. All wells mentioned above are approximately 50% working interest wells to Contango. Next, we will begin completion operations on the State Spearhead #1H, also in mid-November 2019, which is a 25% working interest well. The State Spearhead #1H is the final lease obligation well required until 2021.

Additionally, we are currently preparing to begin completion operations on a drilled but uncompleted well we acquired in connection with the White Star acquisition. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information. The Margaret 35-23N-5W #1MH is expected to be completed in early December 2019. We own a 53% working interest in this well.

We do not currently plan to commit any additional near-term drilling capital to West Texas, and other areas, except to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand our presence in those existing areas, or to add production and cash flow at attractive rates of return. 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

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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.

Impairment of Long-Lived Assets

We recognized non-cash proved property impairment of $0.2 million during the nine months ended September 30, 2019,  related to leases in Wyoming and an onshore non-operated property in  an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.  No impairment of proved properties was recognized during the three months ended September 30, 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 non-cash impairment expense of approximately $1.2 million and $2.0 million during the three and the nine months ended September 30, 2019,  respectively, related to impairment of certain unproved properties primarily due to expiring leases.

Summary Production Information

Our production for the three months ended September 30, 2019 was approximately 59% offshore and 41% onshore, volumetrically, and was comprised of 60% natural gas, 25% oil and 15% natural gas liquids. Our production for the three months ended September 30, 2018 was 62% offshore and 38% onshore, volumetrically, and was comprised of approximately 61% natural gas, 21% oil and 18% 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
	September 30, 2018	December 31, 2018	March 31, 2019	June 30, 2019	September 30, 2019
Offshore (1)	27.2	25.3	23.5	19.1	20.0
West Texas	6.4	7.5	5.9	5.9	5.6
Other Onshore (2)	10.0	7.0	6.5	7.3	8.1
	43.6	39.8	35.9	32.3	33.7

(1) Our Vermilion 170 well was sold effective December 1, 2018 and produced at an average daily rate of 2.2 Mmcfe/d during 2018.  The three months ended June 30, 2019  included a decreased production rate of approximately 1.9 Mmcfe/d due to downtime for pipeline and compressor repair and maintenance.

(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 the three months ended December 31, 2018 was primarily due to the Liberty and Hardin County property sale in November 2018.

Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, owns a 37% ownership interest in Exaro. As of September 30, 2019, Exaro had 647 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 18 Mmcfe/d, net to Exaro. As a result of our investment in Exaro, we recognized an investment loss of approximately $0.6 million, net of no tax expense, and investment loss of approximately $0.3 million, net of no tax expense, for the three months ended September 30, 2019 and 2018, respectively. We recognized an investment gain of approximately $0.1 million, net of no tax expense, and an investment loss of approximately $38 thousand, net of no tax expense, for the nine months ended September 30, 2019 and 2018, respectively. See Item 1. Note 9 – “Investment in Exaro Energy III LLC” for additional details related to this investment.

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Non-Core Asset Sales

In fiscal year 2018 and the nine months ended September 30, 2019, we completed certain non-core asset sales to enhance our liquidity, eliminate marginal assets and reduce administrative costs by focusing our efforts on West Texas and recently acquired properties. 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. In June 2019 and July 2019, we sold certain non-core operated assets located in Lavaca and Wharton counties, Texas and Frio and Zavala counties, Texas, respectively, in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the sold properties. 

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Results of Operations for the Three and Nine months ended September 30, 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 three and nine months ended September 30, 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 September 30,						Nine Months Ended September 30,
	2019		2018		%		2019		2018		%
Revenues (thousands):
Oil and condensate sales	$	7,281	$	8,558	(15)	%	$	21,126	$	26,976	(22)	%
Natural gas sales		4,293		7,128	(40)	%		13,792		21,585	(36)	%
NGL sales		973		3,822	(75)	%		4,402		9,832	(55)	%
Total revenues	$	12,547	$	19,508	(36)	%	$	39,320	$	58,393	(33)	%
Production:
Oil and condensate (thousand barrels)
Offshore GOM		9		20	(55)	%		32		56	(43)	%
West Texas		56		70	(20)	%		180		192	(6)	%
Other Onshore		66		48	38	%		171		182	(6)	%
Total oil and condensate		131		138	(5)	%		383		430	(11)	%
Natural gas (million cubic feet)
Offshore GOM		1,545		1,943	(20)	%		4,506		5,934	(24)	%
West Texas		79		74	7	%		231		200	16	%
Other Onshore		234		444	(47)	%		642		1,519	(58)	%
Total natural gas		1,858		2,461	(25)	%		5,379		7,653	(30)	%
Natural gas liquids (thousand barrels)
Offshore GOM		40		74	(46)	%		164		211	(22)	%
West Texas		17		16	6	%		46		41	12	%
Other		19		31	(39)	%		56		105	(47)	%
Total natural gas liquids		76		121	(37)	%		266		357	(25)	%
Total (million cubic feet equivalent)
Offshore GOM		1,836		2,505	(27)	%		5,683		7,538	(25)	%
West Texas		513		591	(13)	%		1,588		1,599	(1)	%
Other Onshore		748		919	(19)	%		2,004		3,236	(38)	%
Total production		3,097		4,015	(23)	%		9,275		12,373	(25)	%
Daily Production:
Oil and condensate (thousand barrels per day)
Offshore GOM		0.1		0.2	(55)	%		0.1		0.2	(43)	%
West Texas		0.6		0.8	(20)	%		0.7		0.7	(6)	%
Other Onshore		0.7		0.5	38	%		0.6		0.7	(6)	%
Total oil and condensate		1.4		1.5	(5)	%		1.4		1.6	(11)	%
Natural gas (million cubic feet per day)
Offshore GOM		16.8		21.1	(20)	%		16.5		21.8	(24)	%
West Texas		0.9		0.8	7	%		0.8		0.7	16	%
Other Onshore		2.5		4.8	(47)	%		2.4		5.5	(58)	%
Total natural gas		20.2		26.7	(25)	%		19.7		28.0	(30)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM		0.4		0.8	(46)	%		0.6		0.8	(22)	%
West Texas		0.2		0.2	6	%		0.2		0.1	12	%
Other		0.2		0.3	(39)	%		0.2		0.4	(47)	%
Total natural gas liquids		0.8		1.3	(37)	%		1.0		1.3	(25)	%

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		%		2019		2018		%
Total (million cubic feet equivalent per day)
Offshore GOM		20.0		27.2	(27)	%		20.8		27.6	(25)	%
West Texas		5.6		6.4	(13)	%		5.8		5.9	(1)	%
Other Onshore		8.1		10.0	(19)	%		7.4		11.8	(38)	%
Total production		33.7		43.6	(23)	%		34.0		45.3	(25)	%
Average Sales Price:
Oil and condensate (per barrel)	$	55.73	$	61.92	(10)	%	$	55.10	$	62.76	(12)	%
Natural gas (per thousand cubic feet)	$	2.31	$	2.90	(20)	%	$	2.56	$	2.82	(9)	%
Natural gas liquids (per barrel)	$	12.82	$	31.59	(59)	%	$	16.56	$	27.45	(40)	%
Total (per thousand cubic feet equivalent)	$	4.05	$	4.86	(17)	%	$	4.24	$	4.72	(10)	%
Expenses (thousands):
Operating expenses	$	5,435	$	6,382	(15)	%	$	16,321	$	19,787	(18)	%
Exploration expenses	$	218	$	425	(49)	%	$	691	$	1,288	(46)	%
Depreciation, depletion and amortization	$	8,473	$	12,853	(34)	%	$	23,602	$	32,836	(28)	%
Impairment and abandonment of oil and gas properties	$	1,336	$	72,524	(98)	%	$	3,170	$	76,628	(96)	%
General and administrative expenses	$	5,879	$	6,724	(13)	%	$	15,340	$	18,804	(18)	%
Loss from investment in affiliates (net of taxes)	$	(608)	$	(270)	125	%	$	(151)	$	(38)	297	%
Selected data per Mcfe:
Operating expenses	$	1.75	$	1.59	10	%	$	1.76	$	1.60	10	%
General and administrative expenses	$	1.90	$	1.67	14	%	$	1.65	$	1.52	9	%
Depreciation, depletion and amortization	$	2.74	$	3.20	(14)	%	$	2.54	$	2.65	(4)	%

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 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 from individual wells naturally declines over time as we produce our reserves.

We reported revenues of $12.5 million for the three months ended September 30, 2019, compared to revenues of $19.5 million for the three months ended September 30, 2018. The decrease in revenues was primarily attributable to the year over year natural decline in natural gas and NGL production from our offshore properties, the impact of 2018 non-core property sales on 2019 production and limited incremental production from new drilling, as we reduced our drilling program to only that which was necessary to satisfy leasehold drilling obligations due to the need to preserve capital in an unstable commodity price environment. Also contributing to the decline in revenues were meaningful, across the board decreases in oil, natural gas and natural gas liquids prices.  

 Total equivalent production was 33.7 Mmcfe/d for the three months ended September 30, 2019, compared to 43.6 Mmcfe/d in the prior year quarter. Net natural gas production for the current quarter was approximately 20.2 Mmcf/d, compared with approximately 26.7 Mmcf/d for the three months ended September 30, 2018,  with approximately 60% of the decline related to non-core property sales, and the remainder primarily due to normal field decline in our offshore properties. NGL production declined from approximately 1,300 barrels per day to 800 barrels per day, mostly related to non-core property sales. Net oil production declined slightly from approximately 1,500 barrels per day to 1,400 barrels per day primarily due to our limiting our drilling program in West Texas for the fourth quarter of 2018 and the first quarter of 2019 to only that which was necessary to satisfy leasehold drilling obligations. 

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Average Sales Prices

The average equivalent sales price realized for the three months ended September 30, 2019 was $4.05 per Mcfe compared to $4.86 per Mcfe for the three months ended September 30, 2018. This decline was attributable primarily to the decrease in the realized price of gas to $2.31 per Mcf in the current quarter, from  $2.90 per Mcf for the prior year quarter, and to the decline in the realized price of NGLs to $12.82 per barrel in the current quarter, from  $31.59 per barrel for the three months ended September 30, 2018. 

Operating Expenses

Operating expenses for the three months ended September 30, 2019 were approximately $5.4 million, or $1.75 per Mcfe, compared to $6.4 million, or $1.59 per Mcfe, for the three months ended September 30, 2018. The table below provides additional detail of operating expenses for each of the three month periods:

	Three Months Ended September 30,
	2019			2018
	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)
Lease operating expenses	$	2,882	$ 0.93	$	4,393	$ 1.09
Production & ad valorem taxes		663	0.21		800	0.20
Transportation & processing costs		657	0.21		1,224	0.30
Workover costs		1,233	0.40		(35)	—
Total operating expenses	$	5,435	1.75	$	6,382	$ 1.59

Lease operating expenses decreased from $4.4 million during the three months ended September 30, 2018 to $2.9 million for the three months ended September 30, 2019,  primarily due to our non-core property sales.

Transportation and processing costs declined from $1.2 million during the three months ended September 30, 2018 to $0.7 million for the three months ended September 30, 2019,  primarily due to a higher accrual in 2018 for an anticipated pipeline throughput commitment fee deficiency. As of March 31, 2019, the throughput commitment fee deficiency was fully accrued through the expiration of the contract in March 2020. See Item 1. Note 12 – “Commitments and Contingencies” for further information regarding the throughput commitment fee.

Workover costs were higher in the current year quarter primarily due to $0.5 million related to the workover of one well, which was more challenging than expected due to limited downhole data and prior operator well history, and $0.3 million in costs to enhance our West Texas production and water infrastructure facilities to make them more operationally and cost efficient, with less maintenance, going forward. Our operations personnel also focused on production enhancing efforts on certain of our conventional assets during the current quarter. 

Impairment and Abandonment Expenses

During the three months ended September 30, 2019, we recognized no proved property impairment.  During the three months ended September 30, 2018,  we recognized $72.2 million in total offshore and onshore non-cash proved property impairment charges. Included in offshore proved property impairment expense for the 2018 quarter was a $59.4 million impairment of the carrying costs of our Gulf of Mexico properties due primarily to revised proved reserve estimates made during that quarter, as a result of new bottom hole pressure data gathered during the planned installation of a second stage compression in our Eugene Island 11 field. The three months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million related to the impairment of certain of our non-core properties in Southeast Texas, which were reduced to their fair value as a result of a planned sale. See Item 2. Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas. During the three months ended September 30, 2019 and 2018, we recognized non-cash unproved impairment expense of approximately $1.2 million and approximately $0.1 million, respectively,  related to expiring leases. 

We recognized abandonment expense of approximately $0.2 million during each of the three months ended September 30, 2019 and September 30, 2018.

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Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the three months ended September 30, 2019 was approximately $8.5 million, or $2.74 per Mcfe. This compares to approximately $12.9 million, or $3.20 per Mcfe, for the three months ended September 30, 2018.  The lower depletion expense in the current quarter was attributable to lower production, while the lower unit rate resulted from the reduction in the Gulf of Mexico rate due to the impairment in 2018 and the impact of the sale of higher cost properties during 2018.

General and Administrative Expenses

Total general and administrative expenses for the three months ended September 30, 2019 were approximately $5.9 million, compared to $6.7 million for the three months ended September 30, 2018, primarily driven by lower expenses related to wages, bonuses, and employee benefits and fees related to insurance, office costs and other company expenses due to a focused cost reduction strategy.

The table below provides additional detail of general and administrative expenses for each of the three month periods:

	Three Months Ended September 30,
	2019		2018
	(in thousands)
Wages, bonuses and employee benefits (1)	$	717	$	1,607
Non-cash stock-based compensation (1)		557		765
Professional fees (2)		1,563		1,330
Professional fees - special (3)		94		—
Legal judgements (4)		2,134		—
Other (5)		814		3,022
Total general and administrative expenses	$	5,879	$	6,724

(1) Lower expense primarily due to lower head count in 2019.

(2) Primarily includes fees related to recurring legal, consultants, and accounting and auditing.

(3) Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives.

(4) Includes accruals for legal judgements received subsequent to quarter-end. See Item 1. Note 12 – “Commitments and Contingencies” for more information.

(5) Includes fees related to insurance, office costs and other company expenses. 2018 expense includes a severance payment to the former CEO.

Loss from Affiliates

For the quarters ended September 30, 2019 and September 30, 2018, we recorded a loss from affiliates of approximately $0.6 million, net of no tax expense, and a loss of approximately $0.3 million, net of no tax expense, respectively, related to our investment in Exaro.

Gain from Sale of Assets

During the three months ended September 30, 2019, we recorded a gain on sale of assets of $0.2 million related to the sale of certain minor, non-core operated assets in Lavaca, Live Oak and McMullen counties, Texas. During the three months ended September 30, 2018 we recorded a gain on sale of assets of $0.5 million related to the sale of energy credits to a third party.

Nine months ended September 30, 2019 Compared to Nine months ended September 30, 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 from individual wells naturally declines over time as we produce our reserves.

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We reported revenues of $39.3 million for the nine months ended September 30, 2019, compared to revenues of $58.4 million for the nine months ended September 30, 2018. The decline in revenues was primarily attributable to lower gas production from our offshore properties and lower oil production due to the limited drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 because of the unstable oil price environment, as well as lower commodity prices during the current year.

Total equivalent production was 34.0 Mmcfe/d for the nine months ended September 30, 2019, compared to 45.3 Mmcfe/d in the prior year quarter. Net natural gas production for the nine months ended September 30, 2019 was approximately 19.7 Mmcf/d, compared with approximately 28.0 Mmcf/d for the nine months ended September 30, 2018,  with approximately 60% of the decline related to non-core property sales during 2018, and the remainder primarily due to normal field decline in our offshore properties. NGL production declined from approximately 1,300 barrels per day to 1,000 barrels per day, mostly related to non-core property sales. Net oil production declined from approximately 1,600 barrels per day to 1,400 barrels per day primarily due to the limited drilling program we pursued in West Texas for the fourth quarter of 2018 and first quarter of 2019. The higher-unit value oil and NGL production (but lower volume equivalency than gas) increased from 38% to 42% of total production due to our focus on our oil-weighted West Texas drilling program. West Texas accounted for 17% of total equivalent production for the nine months ended September 30, 2019, as compared to 13% of total equivalent production for the nine months ended September 30, 2018. 

Average Sales Prices

The average equivalent sales price realized for the nine months ended September 30, 2019 was $4.24 per Mcfe compared to $4.72 per Mcfe for the nine months ended September 30, 2018. This decrease was attributable primarily to the decrease in the realized price of oil to $55.10 per barrel, from  $62.76 per barrel for the nine months ended September 30, 2018, and to the decrease in the realized price of NGLs to $16.56 per barrel, from  $27.45 per barrel for the nine month period in 2018.  

Operating Expenses

Operating expenses for the nine months ended September 30, 2019 were approximately $16.3 million, or $1.76 per Mcfe, compared to $19.8 million, or $1.60 per Mcfe, for the nine months ended September 30, 2018. The table below provides additional detail of operating expenses for each of the nine month periods:

	Nine Months Ended September 30,
	2019			2018
		(in thousands)	(per Mcfe)		(in thousands)	(per Mcfe)
Lease operating expenses	$	10,196	$ 1.09	$	14,289	$ 1.15
Production & ad valorem taxes		1,706	0.18		2,418	0.20
Transportation & processing costs		1,854	0.20		2,106	0.17
Workover costs		2,565	0.29		974	0.08
Total operating expenses	$	16,321	1.76	$	19,787	$ 1.60

Lease operating expenses decreased from $14.3 million during the nine months ended September 30, 2018 to $10.2 million for the nine months ended September 30, 2019, primarily due to our non-core property sales.

Production and ad valorem expenses decreased from $2.4 million during the nine months ended September 30, 2018 to $1.7 million for the nine months ended September 30, 2019, primarily as a result of lower production and revenue.

Workover costs were higher in the current year primarily due to $0.8 million in costs to enhance our West Texas production and water infrastructure facilities to make them more operationally and cost efficient, with reduced future maintenance, and $0.7 million related to the workover of one well which was more challenging than expected due to limited downhole data and prior operator well history. Our operations personnel also focused on production enhancing efforts on certain of our conventional assets during the current year. 

Impairment and Abandonment Expenses

During the nine months ended September 30, 2019, we recognized $0.2 million in non-cash proved property impairments, while we recognized $74.9 million in total offshore and onshore non-cash proved property impairment

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charges in the 2018 period. Included in offshore proved property impairment expense for the nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of our Gulf of Mexico properties primarily due to revised proved reserve estimates made during the third quarter of 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in our Eugene Island 11 field. Offshore non-cash proved property impairment expense for the 2018 period also included $2.3 million impairment  related to our Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018.  The nine months ended September 30, 2018 included onshore proved property impairment expense of $12.8 million related to certain of our non-core proved properties in Southeast Texas, which were reduced to their fair value as a result of a planned sale. See Item 1. Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas. During the nine months ended September 30, 2019 and 2018, we recognized non-cash impairment expense of approximately $2.0 million and approximately $1.3 million, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

We recognized abandonment expense of approximately $0.9 million and $0.5 million during the nine months ended September 30, 2019 and September 30, 2018, respectively.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the nine months ended September 30, 2019 was approximately $23.6 million, or $2.54 per Mcfe compared to approximately $32.8 million, or $2.65 per Mcfe, for the nine months ended September 30, 2018.  The lower depletion expense for the nine months ended September 30, 2019 was attributable to lower production.

General and Administrative Expenses

Total general and administrative expenses for the nine months ended September 30, 2019 were approximately $15.3 million, compared to $18.8 million for the nine months ended September 30, 2018, primarily driven by lower expenses related to wages, bonuses, and employee benefits and fees related to insurance, office costs and other company expenses due to a focused cost reduction strategy.  

The table below provides additional detail of general and administrative expenses for each of the nine month periods:

	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Wages, bonuses and employee benefits (1)	$	2,774	$	6,049
Non-cash stock-based compensation (1)		2,194		3,772
Professional fees (2)		3,690		3,371
Professional fees - special (3)		1,830		—
Legal judgements (4)		2,134		—
Other (5)		2,718		5,612
Total general and administrative expenses	$	15,340	$	18,804

(1) Lower expense primarily due to lower head count in 2019.

(2) Primarily includes fees related to recurring legal, consultants, and accounting and auditing.

(3) Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives.

(4) Includes accruals for legal judgements received subsequent to quarter-end. See Item 1. Note 12 – “Commitments and Contingencies” for more information.

(5) Includes fees related to insurance, office costs and other company expenses. 2018 expense includes a severance payment to the former CEO.

Gain from Affiliates

For the nine months ended September 30, 2019 and September 30, 2018, we recorded a gain from affiliates of approximately $0.1 million, net of no tax expense, and a loss of $38 thousand, net of no tax expense, respectively, related to our investment in Exaro.

36

Gain from Sale of Assets

During the nine months ended September 30, 2019, we recorded a gain on sale of assets of approximately $0.6 million primarily related to the sale of our non-core assets in Frio, Lavaca, Wharton and Zavala counties, Texas and post-closing adjustments from sales of non-core properties during 2018 and earlier in 2019. During the nine months ended September 30, 2018, we recorded a gain on sale of assets of approximately $11.3 million, including a $9.5 million gain from the sale of our operated Eagle Ford Shale assets in Karnes County, Texas, a $1.3 million gain from the sale of our non-operated assets in Starr County, Texas and a $0.5 million gain from the sale of energy credits to a third party.

Capital Resources and Liquidity

During the nine months ended September 30, 2019, we incurred expenditures of $34.2 million on capital projects, including $26.3 million for our drilling program in the Southern Delaware Basin and $2.5 million in leasehold acquisition costs in the Southern Delaware Basin. We also incurred $2.2 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 capitalized workovers.

Our capital expenditure forecast for all of 2019 is approximately $41.8 million, including $35.3 million in the Southern Delaware Basin. We brought two newly-drilled West Texas wells on production during the current quarter and plan to bring the remaining two wells drilled in 2019 online during the fourth quarter of 2019. We are currently preparing to begin completion operations on a drilled but uncompleted well we acquired in connection with the White Star acquisition, the Margaret 35-23N-5W #1MH, which is expected to be completed in early December 2019. We own a 53% working interest in this well.  We believe that our internally generated cash flows and proceeds from the sale of non-core assets, combined with availability under the Credit Agreement (as defined below), 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.

In September 2019, we entered into a purchase agreement with Will Energy and a purchase agreement with White Star to purchase certain producing assets and undeveloped acreage. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information. As of September 30, 2019, we paid $14.1 million in deposits related to these two acquisitions, which is included in “Other current assets” on the consolidated balance sheet and as “Decrease (increase) in deposits and other” on the consolidated statement of cash flows. Closing of the Will Energy acquisition occurred on October 25, 2019, for aggregate consideration of $23 million.  Following adjustments for recent sales of non-core, non-operated Louisiana properties by Will Energy, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.75 million in cash, including the $1.6 million deposit, and 3.5 million shares of our common stock. Closing of the White Star acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was $95.6 million in cash, including the $12.5 million deposit.

The Will Energy acquisition was partially funded with proceeds from a public offering of our common stock and a private placement of Series A contingent convertible preferred stock, both completed on September 12, 2019, from which we received total net proceeds of $53.7 million. The White Star acquisition was partially funded with proceeds from a private placement of Series B contingent convertible preferred stock, completed on November 1, 2019, from which we received total net proceeds of approximately $21 million. See  Item 1. Note 1 – “Organization and Business” for more information regarding the public offering and private purchase agreements. The remaining cash consideration was funded through borrowings under our Credit Agreement (as defined below).  

37

Cash From Operating Activities

Cash flows provided by operating activities were approximately $9.2 million in cash for the nine months ended September 30, 2019 compared to $25.1 million provided by operating activities for the same period in 2018. Included in the 2019 activity is $14.1 million in paid deposits related to the Will Energy and White Star acquisitions. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information. The table below provides additional detail of cash flows from operating activities for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	7,666	$	16,292
Changes in operating assets and liabilities		1,581		8,851
Net cash provided by operating activities	$	9,247	$	25,143

Cash From Investing Activities

Net cash flows used in investing activities were $27.3 million for the nine months ended September 30, 2019,  substantially all of which was related to cash capital costs for leasehold and drilling costs in the Southern Delaware Basin and non-operated wells in the Georgetown formation. 

Net cash flows used in investing activities were $21.2 million for the nine months ended September 30, 2018.  We expended $43.2 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 year,  partially offset by $22.1 million provided by the sale of our non-core properties in Karnes and Starr counties, Texas and the sale of energy credits to a third party.

Cash From Financing Activities

Cash flows provided by financing activities for the nine months ended September 30, 2019 were approximately $20.1 million. Included in 2019 activity was $53.7 million in total net proceeds from our equity offerings, $61 million in repaid borrowings for the termination of our previous credit facility and $28.1 million in net borrowings under our new Credit Agreement (as defined below).  Cash flows used in financing activities for the nine months ended September 30, 2018 were approximately $4.0 million, primarily related to net repayment of borrowings outstanding under our previous credit agreement.

Credit Agreement

On September 17, 2019, we entered into a new revolving credit agreement with JPMorgan Chase Bank (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million.  The borrowing base is subject to semi-annual redeterminations and may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The next redetermination will occur on or about December 1, 2019. Beginning in 2020, the semi-annual redeterminations will occur on May 1st and November 1st of each year. The Credit Agreement matures on September 17, 2024.  As of September 30, 2019,  the borrowing availability under the Credit Agreement was $35.0 million.

The Credit Agreement contains customary and typical restrictive covenants. Commencing in the quarter ending December 31, 2019, the Credit Agreement requires 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 Agreement.  

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 Item 1. 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.

38

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Item 1. 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 September 30, 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 September 30, 2019. Based upon that evaluation, our President and Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of September 30, 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 three months ended September 30, 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 Item 1. 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 and in Item 1A. of Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019.

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

As reported on the Company’s Current Report on Form 8-K filed on September 18, 2019, during the quarter ended September 30, 2019, the Company entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder of the Company, to issue and sell in a private placement 789,474 convertible preferred shares, which resulted in net proceeds of approximately $7.5 million. The private placement was undertaken in reliance upon an exemption from the registration requirements of the Securities Act, pursuant to Section 4(a)(2) thereof.

Item 3.Defaults upon Senior Securities

None.

39

Item 4.Mine Safety Disclosures

Not applicable.

Item 5.Other Information   

None.

Item 6.Exhibits      

Exhibit Number	Description
2.1	Asset Purchase and Sale Agreement, dated as of September 30, 2019, by and among Contango Oil  & Gas Company, White Star Petroleum, LLC, White Star Petroleum II, LLC, White Star Petroleum Operating, LLC and, solely for the purposes described therein, White Star Petroleum Holdings, LLC and WSP Finance Corporation (filed as Exhibit 2.1 to the Company’s Report on Form 8-K dated September 30, 2019, as filed with the Securities and Exchange Commission on October 1, 2019 and incorporated by reference herein).
3.1	Amended and Restated Certificate of Formation of Contango Oil & Gas Company (filed as Exhibit 3.3 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.2	Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.3	Statement of Resolution Establishing Series of Shares Designated Series A Contingent Convertible Preferred Stock of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s Report on Form 8-K dated September 12, 2019, as filed with the Securities and Exchange Commission on September 18, 2019 and incorporated by reference herein).
10.1	Credit Agreement, dated September 17, 2019, by and among Contango Oil  & Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of JPMorgan Chase Bank, N.A., Royal Bank of Canada and Cadence Bank, N.A. (filed as Exhibit 10.3 to the Company’s Report on Form 8-K dated September 12, 2019, as filed with the Securities and Exchange Commission on September 18, 2019 and incorporated by reference herein).
10.2	Registration Rights Agreement, dated September 17, 2019, by and among Contango Oil & Gas Company and each of the parties set forth in Schedule A thereto (filed as Exhibit 10.2 to the Company’s Report on Form 8-K dated September 12, 2019, as filed with the Securities and Exchange Commission on September 18, 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.

40

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, thereunto duly authorized.

		CONTANGO OIL & GAS COMPANY
Date: November 12, 2019	By:	/s/  WILKIE S. COLYER
		Wilkie S. Colyer
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: November 12, 2019	By:	/s/  E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

41

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: November 12, 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: November 12, 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 September 30, 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: November 12, 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 September 30, 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: November 12, 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	9 Months Ended
	Sep. 30, 2019	Nov. 06, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Entity Registrant Name	CONTANGO OIL & GAS CO
Entity Central Index Key	0001071993
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding		89,357,332
Entity Current Reporting Status	Yes
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (21,417)	$ (87,765)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	23,602	32,836
Impairment of natural gas and oil properties	2,246	76,175
Deferred income taxes	424
Gain on sale of assets	(601)	(11,315)
Loss (gain) from investment in affiliates	(151)	(38)
Stock-based compensation	2,193	3,772
Unrealized loss on derivative instruments	1,068	2,551
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables	590	355
Decrease in prepaids	308	702
Increase (decrease) in accounts payable & advances from joint owners	14,871	3,571
Increase (decrease) in Other Accrued Liabilities	1,211	964
Increase in income taxes receivable, net	(454)
Increase (decrease) in income taxes payable, net	(126)	208
Increase (decrease) in deposits and other	14,819	(3,051)
Net cash provided by operating activities	9,247	25,143
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(27,309)	(43,223)
Additions to furniture & equipment	(17)
Sale of oil & gas properties	10	21,562
Sale of energy credits		497
Net cash used in investing activities	(27,316)	(21,164)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	137,655	182,319
Repayments under credit facility	(169,554)	(185,928)
Net proceeds from equity offering	53,650
Purchase of treasury stock	(236)	(370)
Debt issuance costs	(1,402)
Net cash used in financing activities	20,113	(3,979)
NET CHANGE IN CASH AND CASH EQUIVALENTS	2,044	0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	0	0
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 2,044	$ 0

XML

Acquisitions and Dispositions

9 Months Ended

Sep. 30, 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 $9.5 million, after final closing adjustments.

On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a gain of $1.3 million after removal of the asset retirement obligations associated with the sold properties and final closing adjustments.

On September 11, 2018, the Company entered into a definitive agreement to divest certain of its non-core assets in Liberty and Hardin counties in Southeast Texas. As a result of the sale, the Company reduced the value of the assets to their purchase price and recorded an impairment of approximately $12.8 million during the three months ended September 30, 2018. The sale was completed on November 2, 2018 for cash proceeds of $6.0 million.

On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million after removal of the asset retirement obligations associated with the sold properties.

On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties.

On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 159,872 net acres located in North Louisiana (12,560 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,312 net acres). As of September 30, 2019, the Company paid a $1.6 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the Will Energy acquisition occurred on October 25, 2019, for a total aggregate consideration of $23 million.  Following adjustments for recent sales of non-core, non-operated Louisiana properties by Will Energy, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.75 million in cash, including the $1.6 million deposit, and 3.5 million shares of common stock.

On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 315,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. As of September 30, 2019, the Company paid a $12.5 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the White Star acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.6 million in cash, including the $12.5 million deposit.

XML

Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 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 nine months ended September 30, 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.

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. During the nine months ended September 30, 2019, the Company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.  No impairment expense was recognized during the three months ended September 30, 2019.

During the three and nine months ended September 30, 2018, the Company recognized $72.2 million and $74.9 million in total offshore and onshore non-cash proved property impairment charges, respectively. Included in offshore proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of the Company’s Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Eugene Island 11 field. Offshore non-cash proved property impairment expense for the nine months ended September 30, 2018 included an additional $2.3 million related to the Company’s Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. The three and nine months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, substantially all of which was related to the reduction in fair value on certain of the Company’s non-core properties in Southeast Texas, as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recognized non-cash impairment expense of approximately $1.2 million and approximately $2.0 million for the three and nine months ended September 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, also related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Loss Per Common Share

Net Loss Per Common Share 

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and nine months ended September 30, 2019, the Company excluded 2,621,614 shares or units and 1,115,719 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. For the three and nine months ended September 30, 2018, the Company excluded 884,948 shares or units and 1,328,884 shares or units, respectively, 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 joint and several and 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 Topic 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 did not recognize 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 a 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 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 nine months ended September 30, 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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Investment In Exaro Energy III LLC

9 Months Ended

Sep. 30, 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 September 30, 2019 was approximately $5.9 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results or production in those reported for the Company’s consolidated results.

The Company’s share in Exaro’s results of operations recognized for the three months ended September 30, 2019 and 2018 was a loss of $0.6 million, net of no tax expense, and a loss of $0.3 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the nine months ended September 30, 2019 and 2018 was a gain of $0.1 million, net of no tax expense, and a loss of $38 thousand, net of no tax expense, respectively. 

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Derivative Instruments

9 Months Ended

Sep. 30, 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 September 30, 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 Agreement or under unsecured lines of credit with non-bank counterparties. See Note 10 – “Long-Term Debt” for further information regarding the Credit Agreement.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations.

As of September 30, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	Nov 2019 - Dec 2019	Swap	445,000	Mmbtus	$	2.62			(1)	$	180
Crude Oil	Oct 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(24)
Crude Oil	Oct 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	14
Crude Oil	Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	162
Crude Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	439
Crude Oil	Oct 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72			(3)	$	57
Crude Oil	Oct 2019 - Dec 2019	Swap	1,500	Bbls	$	57.67			(3)	$	17
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.841			(1)	$	341
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532			(1)	$	370
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.532			(1)	$	21
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.696			(1)	$	133
Crude Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74			(3)	$	720
Crude Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			(3)	$	623
Crude Oil	Jan 2020 - March 2020	Swap	2,700	Bbls	$	54.33			(3)	$	12
Crude Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33			(3)	$	20
Crude Oil	July 2020	Swap	5,500	Bbls	$	54.33			(3)	$	18
Crude Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33			(3)	$	26
Crude Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33			(3)	$	27
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.505			(1)	$	(82)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.505			(1)	$	90
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.505			(1)	$	3
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.508			(1)	$	(76)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.508			(1)	$	94
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.508			(1)	$	3
		Total net fair value of derivative instruments								$	3,188

(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.

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing crude 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. The fair value of this costless swap agreement was in a liability position of $0.1 million as of September 30, 2019.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	3,134	$	—	$	3,134
Liabilities	$	(24)	$	—	$	(24)

(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 three and nine months ended September 30, 2019 and 2018 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Crude oil contracts	$	500	$	(1,136)	$	1,442	$	(2,846)
Natural gas contracts		371		57		694		436
Realized gain (loss)	$	871	$	(1,079)	$	2,136	$	(2,410)
Crude oil contracts	$	1,049	$	(152)	$	(2,029)	$	(1,747)
Natural gas contracts		(39)		(88)		961		(804)
Unrealized gain (loss)	$	1,010	$	(240)	$	(1,068)	$	(2,551)
Gain (loss) on derivatives, net	$	1,881	$	(1,319)	$	1,068	$	(4,961)

In October 2019, in conjunction with the closing of the Will Energy acquisition (see Note 3 – “Acquisitions and Dispositions” for more information), the Company acquired the following additional derivative contracts with counterparties that are certain members of its credit facility lender group:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	October 2019	Collar	40,524	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	November 2019	Collar	46,377	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	December 2019	Collar	40,524	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	Jan 2020 - March 2020	Collar	225,000	Mmbtus	$	2.45	-	3.40	(1)
Natural Gas	October 2019	Collar	186,000	Mmbtus	$	2.50	-	2.975	(1)
Natural Gas	November 2019	Collar	180,000	Mmbtus	$	2.50	-	2.975	(1)
Natural Gas	December 2019	Collar	186,000	Mmbtus	$	2.50	-	2.975	(1)
Crude Oil	Oct 2019 - Dec 2019	Collar	4,000	Bbls	$	45.00	-	81.00	(2)
Crude Oil	Jan 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00	-	65.70	(2)

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

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

In the fourth quarter of 2019, the Company entered into the following additional derivative contracts:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Dec 2019	Swap	330,000	Mmbtus	$	2.813	(1)
Natural Gas	Dec 2019	Swap	330,000	Mmbtus	$	2.81	(1)
Natural Gas	Jan 2020 - March 2020	Swap	300,000	Mmbtus	$	2.53	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53	(1)
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.53	(1)
Natural Gas	Jan 2020 - March 2020	Swap	300,000	Mmbtus	$	2.532	(1)
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532	(1)
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.532	(1)
Natural Gas	Jan 2021 - March 2021	Swap	650,000	Mmbtus	$	2.508	(1)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	Mmbtus	$	2.508	(1)
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	Mmbtus	$	2.508	(1)
Crude Oil	Nov 2019 - Dec 2019	Swap	88,000	Bbls	$	56.80	(2)
Crude Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.70	(2)
Crude Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.70	(2)
Crude Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70	(2)
Crude Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.58	(2)
Crude Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.58	(2)
Crude Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58	(2)
Crude Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(2)
Crude Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(2)
Crude Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(2)
Crude Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(2)
Crude Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(2)
Crude Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(2)

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

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

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Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Assets
Gross	$ 3,134	$ 4,600
Total	3,134	4,600
Liabilities:
Gross	(24)	(422)
Total	$ (24)	$ (422)

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Leases - Balance sheet (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2019 USD ($)
Leases
Lease, Practical Expedients, Package [true false]	true
Balance sheet information
Operating lease right of use asset - current	$ 690
Operating lease right of use asset - long-term	489
Total operating lease right of use asset	1,179
Operating lease liability - current	$ (690)
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts Payable and Accrued Liabilities, Current
Operating lease liability - long-term	$ (489)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Liabilities, Noncurrent
Total operating lease liability	$ (1,179)
Financing lease right of use asset - current	19
Financing lease right of use asset - long-term	70
Total financing lease right of use asset	89
Financing lease liability - current	$ (17)
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts Payable and Accrued Liabilities, Current
Financing lease liability - long-term	$ (74)
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Liabilities, Noncurrent
Total financing lease liability	$ (91)

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Summary of Significant Accounting Policies (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Significant Accounting Policies [Line Items]
Potentially dilutive (in shares)	2,621,614	884,948	1,115,719	1,328,884
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

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Other Financial Information (Tables)

9 Months Ended

Sep. 30, 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):

	September 30, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	4,463	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,005		3,833
Income taxes receivable		878		424
Other receivables		1,054		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,118	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	848	$	792
Other		147		511
Total prepaid expenses and other	$	995	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	12,704	$	17,986
Advances from partners (1)		13,657		1,785
Accrued exploration and development (1)		12,036		4,751
Accrued acquisition costs		3,763		4,352
Trade payables (1)		12,441		3,385
Accrued general and administrative expenses (2)		4,365		2,545
Accrued operating expenses		1,651		1,801
Other accounts payable and accrued liabilities		2,127		2,901
Total accounts payable and accrued liabilities	$	62,744	$	39,506

(1) Increase in 2019 primarily due to an increase in drilling and completion activity in West Texas during the three months ended September 30, 2019. The Company limited its drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 to only that which was necessary to meet leasehold drilling obligations.

(2) Includes a $2.1 million accrual related to a legal judgement determined during the three months ended September 30, 2019. See Note 12 – Commitments and Contingencies” for more information.

Schedule Of Supplemental Disclosures

Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2019 and 2018 (in thousands):

		Nine Months Ended September 30,
		2019		2018
Cash payments:
Interest payments	$	3,037	$	3,846
Income tax payments	$	668	$	81
Non-cash investing activities in the consolidated statements of cash flows:
Increase in accrued capital expenditures	$	7,284	$	2,764

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Investment in Exaro Energy III LLC (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Schedule of Equity Method Investments Financials
Gain (loss) from investment in affiliates, net of income taxes	$ (608)	$ (270)	$ (151)	$ (38)
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Equity method investment, ownership percentage	37.00%		37.00%
Share of equity in investment	$ 5,900		$ 5,900
Gain (loss) from investment in affiliates, net of income taxes	(600)	(300)	100	(38)
Tax (expense) benefit from equity investment	$ 0	$ 0	$ 0	$ 0

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Summary of Significant Accounting Policies - Impairment and Debt (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($) item	Sep. 30, 2018 USD ($)	Dec. 31, 2018
Policies
Impairment of natural gas and oil properties			$ 2,246	$ 76,175
Debt issuance costs incurred			$ 1,402
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	$ 72,200	$ 200	74,900
Proved property [Member] | Gulf of Mexico Properties [Member]
Policies
Impairment of natural gas and oil properties		59,400		59,400
Proved property [Member] | Vermilion 170 [Member]
Policies
Impairment of natural gas and oil properties				2,300
Proved property [Member] | Onshore Properties [Member]
Policies
Impairment of natural gas and oil properties		12,800		13,200
Unproved property [Member]
Policies
Impairment of natural gas and oil properties	$ 1,200	$ 100	$ 2,000	$ 1,300

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases

Summary of balance sheet information related to the leases

The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2019 (in thousands):

	September 30, 2019
Operating lease right of use asset - current (1)	$	690
Operating lease right of use asset - long-term (2)		489
Total operating lease right of use asset	$	1,179
Operating lease liability - current (3)	$	(690)
Operating lease liability - long-term (4)		(489)
Total operating lease liability	$	(1,179)
Financing lease right of use asset - current (1)	$	19
Financing lease right of use asset - long-term (2)		70
Total financing lease right of use asset	$	89
Financing lease liability - current (3)	$	(17)
Financing lease liability - long-term (4)		(74)
Financing lease liability - current	$	(91)

(1) Included in “Other current assets” on the consolidated balance sheet.

(2) Included in “Other non-current assets” on the consolidated balance sheet.

(3) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet.

(4) Included in “Other long-term liabilities” on the consolidated balance sheet.

Summary of weighted average remaining lease terms and weighted average discount rates

The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2019:

	September 30, 2019
Weighted Average Remaining Lease Terms (in months):
Operating leases	21
Financing leases	57
Weighted Average Discount Rate:
Operating leases	5.31%
Financing leases	6.00%

Summary of maturities for the Company’s lease liabilities on the consolidated balance sheet, Operating lease

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2019, were as follows (in thousands):

	September 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after September 30, 2019)	$	170	$	6
2020		677		17
2021		324		18
2022		8		19
2023		-		20
2024		-		11
Total future minimum lease payments		1,179		91
Less: imputed interest		(57)		(14)
Present value of lease liabilities	$	1,122	$	77

Summary of maturities for the Company’s lease liabilities on the consolidated balance sheet, Finance lease

	September 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after September 30, 2019)	$	170	$	6
2020		677		17
2021		324		18
2022		8		19
2023		-		20
2024		-		11
Total future minimum lease payments		1,179		91
Less: imputed interest		(57)		(14)
Present value of lease liabilities	$	1,122	$	77

Summary of operating lease costs

The following table summarizes expenses related to the Company’s leases for the three and nine months ended September 30, 2019 (in thousands):

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1) (2)	$	138	$	609
Financing lease cost		5		5
Administrative lease cost (3)		19		56
Short-term lease cost (1) (4)		781		3,359
Total lease cost	$	943	$	4,029

(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 an office lease which expired on March 31, 2019 and a new office lease which began on April 1, 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 drilling rig and compressor agreements with lease terms of more than one month and less than one year.

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Long-Term Debt (Details) $ in Thousands		3 Months Ended		9 Months Ended
	Sep. 17, 2019 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Nov. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Debt issuance costs incurred				$ 1,402
Interest expense		$ 998	$ 1,411	3,169	$ 4,082
JPMorgan Chase Bank [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 65,000					$ 145,000
Line of credit, available		35,000		35,000
Credit facility amount outstanding		28,100		28,100
Letters of credit amount outstanding		$ 1,900		$ 1,900
Weighted average interest rate (as a percent)		5.40%		5.40%
Current ratio, minimum	1.00
Leverage ratio, maximum	3.50
RBC Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility amount outstanding							$ 60,000
Letters of credit amount outstanding							$ 1,900
Weighted average interest rate (as a percent)							6.30%

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 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 (“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 interim 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 nine months ended September 30, 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.

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. During the nine months ended September 30, 2019, the Company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.  No impairment expense was recognized during the three months ended September 30, 2019.

During the three and nine months ended September 30, 2018, the Company recognized $72.2 million and $74.9 million in total offshore and onshore non-cash proved property impairment charges, respectively. Included in offshore proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of the Company’s Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Eugene Island 11 field. Offshore non-cash proved property impairment expense for the nine months ended September 30, 2018 included an additional $2.3 million related to the Company’s Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. The three and nine months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, substantially all of which was related to the reduction in fair value on certain of the Company’s non-core properties in Southeast Texas, as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recognized non-cash impairment expense of approximately $1.2 million and approximately $2.0 million for the three and nine months ended September 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, also related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Loss Per Common Share 

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and nine months ended September 30, 2019, the Company excluded 2,621,614 shares or units and 1,115,719 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. For the three and nine months ended September 30, 2018, the Company excluded 884,948 shares or units and 1,328,884 shares or units, respectively, 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 joint and several and 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 Topic 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 did not recognize 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 a 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 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 nine months ended September 30, 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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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
REVENUES:
Revenues	$ 12,547	$ 19,508	$ 39,320	$ 58,393
EXPENSES:
Operating expenses	5,435	6,382	16,321	19,787
Exploration expenses	218	425	691	1,288
Depreciation, depletion and amortization	8,473	12,853	23,602	32,836
Impairment and abandonment of oil and gas properties	1,336	72,524	3,170	76,628
General and administrative expenses	5,879	6,724	15,340	18,804
Total expenses	21,341	98,908	59,124	149,343
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates, net of income taxes	(608)	(270)	(151)	(38)
Gain from sale of assets	192	498	601	11,315
Interest expense	(998)	(1,411)	(3,169)	(4,082)
Gain (loss) on derivatives, net	1,881	(1,319)	1,068	(4,961)
Other income	519	357	522	1,239
Total other income (expense)	986	(2,145)	(1,129)	3,473
NET LOSS BEFORE INCOME TAXES	(7,808)	(81,545)	(20,933)	(87,477)
Income tax benefit (provision)	(30)	21	(484)	(288)
NET LOSS	$ (7,838)	$ (81,524)	$ (21,417)	$ (87,765)
NET LOSS PER SHARE:
Basic (in dollars per share)	$ (0.19)	$ (3.26)	$ (0.59)	$ (3.52)
Diluted (in dollars per share)	$ (0.19)	$ (3.26)	$ (0.59)	$ (3.52)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic (in shares)	41,786	25,001	36,518	24,910
Diluted (in shares)	41,786	25,001	36,518	24,910
Oil and Condensate [Member]
REVENUES:
Revenues	$ 7,281	$ 8,558	$ 21,126	$ 26,976
Natural Gas, Production [Member]
REVENUES:
Revenues	4,293	7,128	13,792	21,585
Natural gas liquids [Member]
REVENUES:
Revenues	$ 973	$ 3,822	$ 4,402	$ 9,832

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Other Financial Information

9 Months Ended

Sep. 30, 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):

	September 30, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	4,463	$	6,052
Receivable for Alta Resources distribution		1,712		1,993
Joint interest billings		4,005		3,833
Income taxes receivable		878		424
Other receivables		1,054		223
Allowance for doubtful accounts		(994)		(994)
Total accounts receivable	$	11,118	$	11,531
Prepaid expenses and other:
Prepaid insurance	$	848	$	792
Other		147		511
Total prepaid expenses and other	$	995	$	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	12,704	$	17,986
Advances from partners (1)		13,657		1,785
Accrued exploration and development (1)		12,036		4,751
Accrued acquisition costs		3,763		4,352
Trade payables (1)		12,441		3,385
Accrued general and administrative expenses (2)		4,365		2,545
Accrued operating expenses		1,651		1,801
Other accounts payable and accrued liabilities		2,127		2,901
Total accounts payable and accrued liabilities	$	62,744	$	39,506

(1) Increase in 2019 primarily due to an increase in drilling and completion activity in West Texas during the three months ended September 30, 2019. The Company limited its drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 to only that which was necessary to meet leasehold drilling obligations.

(2) Includes a $2.1 million accrual related to a legal judgement determined during the three months ended September 30, 2019. See Note 12 – Commitments and Contingencies” for more information.

Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2019 and 2018 (in thousands):

		Nine Months Ended September 30,
		2019		2018
Cash payments:
Interest payments	$	3,037	$	3,846
Income tax payments	$	668	$	81
Non-cash investing activities in the consolidated statements of cash flows:
Increase in accrued capital expenditures	$	7,284	$	2,764

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Fair Value Measurements

9 Months Ended

Sep. 30, 2019

Fair Value Measurements [Abstract]

Fair Value Measurements

4. Fair Value Measurements

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. Fair value is 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). A  fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2019.  A financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Fair value information for financial assets and liabilities was as follows as of September 30, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	3,134	$	—	$	3,134	$	—
Commodity price contracts - liabilities	$	(24)	$	—	$	(24)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in 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 September 30, 2019, the Company's derivative contracts were all with major 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 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 Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 – “Long-Term Debt” 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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Commitments and Contingencies

9 Months Ended

Sep. 30, 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 decades-old poorly documented transactions. Based on prior summary judgments, the trial court 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 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. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company has engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case and is seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals ruling.

In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the plaintiff. Prior to the judgement, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgement, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgement plus fees and interest. The Company is currently preparing an appeal of that court decision.

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 net fees of $0.7 million during each of the nine months ended September 30, 2019 and 2018. As of September 30, 2019, the Company estimates that the remaining net deficiency fee will be approximately $0.5 million through the expiration of the contract on March 31, 2020, all of which is currently accrued.

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Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	$ 871	$ (1,079)	$ 2,136	$ (2,410)
Unrealized gain (loss)	1,010	(240)	(1,068)	(2,551)
Gain (loss) on derivatives, net	1,881	(1,319)	1,068	(4,961)
Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	500	(1,136)	1,442	(2,846)
Unrealized gain (loss)	1,049	(152)	(2,029)	(1,747)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	371	57	694	436
Unrealized gain (loss)	$ (39)	$ (88)	$ 961	$ (804)

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Leases - Lease Terms and Discount (Details)	Sep. 30, 2019
Leases
Weighted Average Remaining Lease Terms (in months): Operating leases	21 months
Weighted Average Remaining Lease Terms (in months): Financing leases	57 months
Weighted Average Discount Rate: Operating leases	5.31%
Weighted Average Discount Rate: Financing leases	6.00%

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Acquisitions and Dispositions - Dispositions (Details) - USD ($) $ in Thousands						9 Months Ended
	Jul. 01, 2019	Jun. 10, 2019	Sep. 11, 2018	May 25, 2018	Mar. 28, 2018	Sep. 30, 2019	Sep. 30, 2018	Nov. 02, 2018
Disposals
Impairment of natural gas and oil properties						$ 2,246	$ 76,175
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Karnes County, TX Assets [Member]
Disposals
Cash purchase price					$ 21,000
Gain (loss) on sale of oil and gas property					$ 9,500
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Starr County, TX Assets [Member]
Disposals
Cash purchase price				$ 600
Gain (loss) on sale of oil and gas property				$ 1,300
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Liberty and Hardin County, TX Assets [Member]
Disposals
Cash purchase price								$ 6,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Lavaca and Wharton County, Texas Assets [Member]
Disposals
Gain (loss) on sale of oil and gas property		$ 400
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Frio and Zavala County Texas [Member]
Disposals
Gain (loss) on sale of oil and gas property	$ 200
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Liberty and Hardin County, TX Assets [Member]
Disposals
Impairment of natural gas and oil properties			$ 12,800

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Current tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total	$	30	$	(21)	$	484	$	288
Total tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total income tax provision (benefit)	$	30	$	(21)	$	484	$	288

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2019 (in thousands):

	Total		Fair Value Measurements Using
	CarryingValue		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	3,134	$	—	$	3,134	$	—
Commodity price contracts - liabilities	$	(24)	$	—	$	(24)	$	—

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Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash payments:
Interest payments	$ 3,037	$ 3,846
Income tax payments	668	81
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$ 7,284	$ 2,764

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Commitments and Contingencies (Details) $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
	Nov. 30, 2010 USD ($) site	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Aug. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Legal Proceedings
Accounts payable and accrued liabilities		$ 62,744	$ 62,744			$ 39,506
Lavaca County Case [Member]
Legal Proceedings
Number of wells involved in litigation | site	2
Damages sought by plaintiffs	$ 5,300
Litigation Case Harris County [Member]
Legal Proceedings
Accounts payable					$ 1,100
Loss contingency provision accrual increase		2,100
Throughput commitment
Loss Contingency
Fees incurred			700	$ 700
Estimated deficiency		$ 500	$ 500

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents	$ 2,044
Accounts receivable, net	11,118	$ 11,531
Prepaid expenses	995	1,303
Current derivative asset	2,625	4,600
Other current assets	14,820
Total current assets	31,602	17,434
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	1,110,042	1,095,417
Unproved properties	42,427	34,612
Other property and equipment	1,331	1,314
Accumulated depreciation, depletion and amortization	(912,098)	(898,169)
Total property, plant and equipment, net	241,702	233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates	5,872	5,743
Long-term derivative asset	509
Deferred tax asset		424
Other non-current assets	1,962	357
Total other non-current assets	8,343	6,524
TOTAL ASSETS	281,647	257,132
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	62,744	39,506
Current derivative liability	24	422
Current asset retirement obligations	679	1,329
Current portion of long-term debt		60,000
Total current liabilities	63,447	101,257
NON-CURRENT LIABILITIES:
Long-term debt	28,100
Asset retirement obligations	11,636	12,168
Other long-term liabilities	3,883	3,318
Total non-current liabilities	43,619	15,486
Total liabilities	107,066	116,743
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Series A convertible preferred stock, $0.04 par value, 789,474 shares authorized, issued and outstanding at September 30, 2019	32
Common stock, $0.04 par value, 100 million shares authorized, 85,864,463 shares issued and outstanding at September 30, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018	3,423	1,573
Additional paid-in capital	393,723	339,981
Treasury shares at cost (No shares at September 30, 2019 and 5,458,950 shares at December 31, 2018)		(129,030)
Retained deficit	(222,597)	(72,135)
Total shareholders’ equity	174,581	140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 281,647	$ 257,132

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CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Deficit [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, 2017		$ 1,223	302,527	(128,583)	49,433	224,600
Balance, shares at Dec. 31, 2017		25,505,715
Net income (loss)						(87,765)
Balance at Sep. 30, 2018		$ 1,229	306,293	(128,953)	(38,332)	140,237
Balance, shares at Sep. 30, 2018		25,584,108
Balance at Mar. 31, 2018		$ 1,231	303,943	(128,654)	50,370	226,890
Balance, shares at Mar. 31, 2018		25,695,797
Treasury shares at cost				(124)		(124)
Treasury shares at cost, shares		(33,703)
Restricted shares activity		$ 4	(4)
Restricted shares activity, shares		77,188
Stock-based compensation			1,584			1,584
Net income (loss)					(7,178)	(7,178)
Balance at Jun. 30, 2018		$ 1,235	305,523	(128,778)	43,192	221,172
Balance, shares at Jun. 30, 2018		25,739,282
Treasury shares at cost				(175)		(175)
Treasury shares at cost, shares		(27,860)
Restricted shares activity		$ (6)	6
Restricted shares activity, shares		(127,314)
Stock-based compensation			764			764
Net income (loss)					(81,524)	(81,524)
Balance at Sep. 30, 2018		$ 1,229	306,293	(128,953)	(38,332)	140,237
Balance, shares at Sep. 30, 2018		25,584,108
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
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
Net income (loss)						$ (21,417)
Balance at Sep. 30, 2019	$ 32	$ 3,423	393,723		(222,597)	$ 174,581
Balance, shares at Sep. 30, 2019	789,474	85,864,463				85,864,463
Balance at Mar. 31, 2019		$ 1,585	340,935	(129,216)	(80,753)	$ 132,551
Balance, shares at Mar. 31, 2019		34,416,727
Equity offering-common stock			45			45
Treasury shares at cost				(50)		(50)
Treasury shares at cost, shares		(16,133)
Restricted shares activity		$ 2	(2)
Restricted shares activity, shares		42,249
Stock-based compensation			585			585
Net income (loss)					(4,961)	(4,961)
Balance at Jun. 30, 2019		$ 1,587	341,563	(129,266)	(85,714)	128,170
Balance, shares at Jun. 30, 2019		34,442,843
Equity offering-common stock		$ 2,058	44,181			$ 46,239
Equity offering-common stock, shares		45,922,870				51,400,000
Equity offering-preferred stock	$ 32		7,420			$ 7,452
Equity offering-preferred stock, shares	789,474
Treasury shares reissuance		$ (221)		$ 129,266	(129,045)
Treasury shares reissuance, shares		5,524,498
Restricted shares activity		$ (1)	1
Restricted shares activity, shares		(25,748)
Stock-based compensation			558			558
Net income (loss)					(7,838)	(7,838)
Balance at Sep. 30, 2019	$ 32	$ 3,423	$ 393,723		$ (222,597)	$ 174,581
Balance, shares at Sep. 30, 2019	789,474	85,864,463				85,864,463

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Derivative Instruments (Derivative Contracts) (Details) $ in Thousands	Nov. 12, 2019 item $ / MMBTU $ / bbl	Oct. 31, 2019 item $ / MMBTU $ / bbl	Sep. 30, 2019 USD ($) item $ / MMBTU $ / bbl
Derivative [Line Items]
Fair Value | $			$ 3,188
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			445,000
Price/Unit-Swap | $ / MMBTU			2.62
Fair Value | $			$ 180
Natural Gas [Member] | Swap [Member] | Derivative Contract Period December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	330,000
Price/Unit-Swap | $ / MMBTU	2.813
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	330,000
Price/Unit-Swap | $ / MMBTU	2.81
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	300,000		425,000
Price/Unit-Swap | $ / MMBTU	2.53		2.841
Fair Value | $			$ 341
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	300,000
Price/Unit-Swap | $ / MMBTU	2.532
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	400,000		400,000
Price/Unit-Swap | $ / MMBTU	2.53		2.532
Fair Value | $			$ 370
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	400,000
Price/Unit-Swap | $ / MMBTU	2.532
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			40,000
Price/Unit-Swap | $ / MMBTU			2.532
Fair Value | $			$ 21
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	350,000
Price/Unit-Swap | $ / MMBTU	2.53
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	350,000
Price/Unit-Swap | $ / MMBTU	2.532
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			375,000
Price/Unit-Swap | $ / MMBTU			2.696
Fair Value | $			$ 133
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	650,000		185,000
Price/Unit-Swap | $ / MMBTU	2.508		2.505
Fair Value | $			$ (82)
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			185,000
Price/Unit-Swap | $ / MMBTU			2.508
Fair Value | $			$ (76)
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			120,000
Price/Unit-Swap | $ / MMBTU			2.505
Fair Value | $			$ 90
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			120,000
Price/Unit-Swap | $ / MMBTU			2.508
Fair Value | $			$ 94
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to October 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	400,000
Price/Unit-Swap | $ / MMBTU	2.508
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			10,000
Price/Unit-Swap | $ / MMBTU			2.505
Fair Value | $			$ 3
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			10,000
Price/Unit-Swap | $ / MMBTU			2.508
Fair Value | $			$ 3
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	580,000
Price/Unit-Swap | $ / MMBTU	2.508
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period October 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		40,524
Price/Unit-Floor | $ / MMBTU		2.45
Price/Unit-Cap | $ / MMBTU		3.40
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period October 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		186,000
Price/Unit-Floor | $ / MMBTU		2.50
Price/Unit-Cap | $ / MMBTU		2.975
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period November 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		46,377
Price/Unit-Floor | $ / MMBTU		2.45
Price/Unit-Cap | $ / MMBTU		3.40
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period November 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		180,000
Price/Unit-Floor | $ / MMBTU		2.50
Price/Unit-Cap | $ / MMBTU		2.975
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period December 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		40,524
Price/Unit-Floor | $ / MMBTU		2.45
Price/Unit-Cap | $ / MMBTU		3.40
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period December 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		186,000
Price/Unit-Floor | $ / MMBTU		2.50
Price/Unit-Cap | $ / MMBTU		2.975
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period January to March 2020 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		225,000
Price/Unit-Floor | $ / MMBTU		2.45
Price/Unit-Cap | $ / MMBTU		3.40
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			2,400
Price/Unit-Swap | $ / bbl			61.72
Fair Value | $			$ 57
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period October To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			1,500
Price/Unit-Swap | $ / bbl			57.67
Fair Value | $			$ 17
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			9,000
Price/Unit-Swap | $ / bbl			72.10
Fair Value | $			$ 162
Crude Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	88,000		12,000
Price/Unit-Swap | $ / bbl	56.80		72.10
Fair Value | $			$ 439
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to February 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	42,500
Price/Unit-Swap | $ / bbl	54.70
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period January to February 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	42,500
Price/Unit-Swap | $ / bbl	54.58
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			2,700
Price/Unit-Swap | $ / bbl			54.33
Fair Value | $			$ 12
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			22,000
Price/Unit-Swap | $ / bbl			57.74
Fair Value | $			$ 720
Crude Oil [Member] | Swap [Member] | Derivative Contract Period March to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	37,500
Price/Unit-Swap | $ / bbl	54.70
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period March to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	37,500
Price/Unit-Swap | $ / bbl	54.58
Crude Oil [Member] | Swap [Member] | Derivative Contract Period April to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			2,500
Price/Unit-Swap | $ / bbl			54.33
Fair Value | $			$ 20
Crude Oil [Member] | Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			15,000
Price/Unit-Swap | $ / bbl			57.74
Fair Value | $			$ 623
Crude Oil [Member] | Swap [Member] | Derivative Contract Period July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			5,500
Price/Unit-Swap | $ / bbl			54.33
Fair Value | $			$ 18
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			2,500
Price/Unit-Swap | $ / bbl			54.33
Fair Value | $			$ 26
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	35,000
Price/Unit-Swap | $ / bbl	54.70
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	35,000
Price/Unit-Swap | $ / bbl	54.58
Crude Oil [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			3,500
Price/Unit-Swap | $ / bbl			54.33
Fair Value | $			$ 27
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	19,000
Price/Unit-Swap | $ / MMBTU	50.00
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	62,000
Price/Unit-Swap | $ / bbl	52.00
Crude Oil [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	12,000
Price/Unit-Swap | $ / MMBTU	50.00
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	10,000
Price/Unit-Swap | $ / MMBTU	50.00
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	55,000
Price/Unit-Swap | $ / bbl	52.00
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October to December 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	64,000
Price/Unit-Swap | $ / bbl	52.00
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period October To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			7,000
Price/Unit-Floor | $ / bbl			50.00
Price/Unit-Cap | $ / bbl			58.00
Fair Value | $			$ (24)
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period October To December 2019 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		4,000
Price/Unit-Floor | $ / bbl		45.00
Price/Unit-Cap | $ / bbl		81.00
Crude Oil [Member] | Collar Options [Member] | Derivative Contract 2 Period October To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			4,000
Price/Unit-Floor | $ / bbl			52.00
Price/Unit-Cap | $ / bbl			59.45
Fair Value | $			$ 14
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period January to October 2020 [Member] | Will Energy [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		3,442
Price/Unit-Floor | $ / bbl		52.00
Price/Unit-Cap | $ / bbl		65.70
Crude Oil [Member] | Costless Swap [Member]
Derivative [Line Items]
Price/Unit-Swap | $ / bbl			0.05
Fair Value | $			$ (100)
Crude Oil [Member] | Costless Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			12,000
Crude Oil [Member] | Costless Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			10,000

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Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($)	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Option roll forward
Stock options granted in period (in shares)	0	0
Exercise of stock options, shares	0	0
Expired / Forfeited (in shares)	(12,673)	(4,500)
Stock-based compensation
Excess tax benefit from exercise/cancellation of stock options	$ 0	$ 0

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Leases - Costs (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases
Operating lease cost	$ 138	$ 609
Financing lease cost	5	5
Administrative lease cost	19	56
Short-term lease cost	781	3,359
Total net lease cost	$ 943	4,029
Cash payments relating to operating leases		228
Cash payments relating to finance leases		$ 4

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Long-Term Debt

9 Months Ended

Sep. 30, 2019

Long-Term Debt

Long-Term Debt

10. Long-Term Debt

Credit Agreement    

On September 17, 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base is subject to semi-annual redeterminations. The next redetermination will occur on or about December 1, 2019. Beginning in 2020, the semi-annual redeterminations will occur on May 1st and November 1st of each year. The borrowing base may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The Credit Agreement matures on September 17, 2024.

On September 18, 2019, the Company repaid all obligations with borrowings under the Credit Agreement, and terminated, its previous credit agreement with the Royal Bank of Canada (the “Credit Facility”), which had an October 1, 2019 maturity.

As of September 30, 2019, the Company had approximately $28.1 million outstanding under the Credit Agreement 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 an outstanding letter of credit. As of September 30, 2019, borrowing availability under the Credit Agreement was $35.0 million.

The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement.

Total interest expense under the Company’s current and previous credit agreements, including commitment fees, for the three and nine months ended September 30, 2019 was approximately $1.0 million and $3.2 million, respectively. Total interest expense under the Company’s previous credit agreement, including commitment fees, for the three and nine months ended September 30, 2018 was approximately $1.4 million and $4.1 million, respectively.

The weighted average interest rates in effect at September 30, 2019 and December 31, 2018 were 5.4% under the Credit Agreement and 6.3% under the Credit Facility, respectively.

The Credit Agreement contains customary and typical restrictive covenants. Commencing in the quarter ending December 31, 2019, the Credit Agreement requires 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 Agreement.

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2019

Stock-Based Compensation [Abstract]

Stock-Based Compensation

6. Stock-Based Compensation

Restricted Stock    

During the nine months ended September 30, 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. Additionally, during the nine months ended September 30, 2019, the Company granted 80,410 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2019, was $2.91 per share, with a total fair value of approximately $1.1 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2019, 63,909 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2019 was approximately $0.3 million. The Company recognized approximately $1.7 million in restricted stock compensation expense during the nine months ended September 30, 2019 related to restricted stock granted to its officers, employees and directors. As of September 30, 2019, an additional $1.2 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.7 years. Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2019, assuming PSUs (as defined below) are settled at 100% of target.

During the nine months ended September 30, 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. Additionally, during the nine months ended September 30, 2018, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2018, was $3.76 per share, with a total fair value of approximately $1.2 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2018,  152,294 restricted shares were forfeited by former employees, of which 105,800 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2018 was approximately $1.0 million. The Company recognized approximately $3.2 million in restricted stock compensation expense during the nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 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 $0.5 million in stock compensation expense related to PSUs during the nine months ended September 30, 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 September 30, 2019, an additional $1.0 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.9 years. 

During the nine months ended September 30, 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 nine months ended September 30, 2018,  182,227 PSUs were forfeited by former employees, of which 153,127 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The Company only recognized approximately $0.6 million in stock compensation expense related to PSUs during the nine months ended September 30, 2018, primarily due to the above referenced forfeitures.

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 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 nine months ended September 30, 2019 or 2018.

During the nine months ended September 30, 2019,  no stock options were exercised and stock options for 12,673 shares were forfeited by former employees. During the nine months ended September 30, 2018, no stock options were exercised and stock options for 4,500 shares were forfeited by former employees.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.04
Preferred stock, shares authorized	789,474
Preferred stock, shares issued	789,474
Preferred stock, shares outstanding	789,474
Common stock, par value (in dollars per share)	$ 0.04	$ 0.04
Common stock, shares authorized	100,000,000
Common stock, shares issued	85,864,463	39,617,442
Common stock, shares outstanding	85,864,463	34,158,492
Treasury stock, shares	0	5,458,950

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Organization and Business

9 Months Ended

Sep. 30, 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 Texas and Wyoming properties and use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties across the United States. On June 14, 2019, following approval by the Company’s stockholders at the 2019 annual meeting of stockholders, the Company changed its state of incorporation from the State of Delaware to the State of Texas and increased the Company’s number of authorized shares of common stock from 50 million to 100 million. 

In September 2019, the Company entered into a purchase agreement with Will Energy Corporation (“Will Energy”) and a purchase agreement with White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed subsequent to September 30, 2019. See Note 3 – “Acquisitions and Dispositions” for more information.

Also in September 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations and terminated its previous credit agreement with Royal Bank of Canada, which had an October 1, 2019 maturity. The new revolving credit agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions on October 25 and November 1, 2019, respectively, to add two additional lenders and increase the borrowing base thereunder to $145 million. See Note 10 – “Long-Term Debt” for more information.

The following table lists the Company’s primary producing areas as of September 30, 2019:

Location	Formation
Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas	Wolfcamp A and B
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.

Since 2016, the Company has been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas, which is expected to continue to generate positive returns in the current price environment. As of September 30, 2019, the Company was producing from fourteen wells over its approximate 17,400 gross operated (8,400 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In October 2019, the Company brought two more West Texas wells online and finished completing another West Texas well, which is expected to begin producing in mid-November 2019. Additionally, the Company is currently preparing to begin completion operations on a drilled but uncompleted well which it acquired in connection with the White Star acquisition. See Note 3 – “Acquisitions and Dispositions” for more information.

The Company currently plans to limit its near-term drilling program expenditures, in West Texas and other areas, to only those necessary to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas, or to add production and cash flow at attractive rates of return. The Company will continue to make balance sheet strength a priority in 2019 and 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.

On September 12, 2019, the Company completed an underwritten public offering (the “Public Offering”) of 51,447,368 shares of its common stock (of which 5,524,498 was reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the Series A Private Placement (defined below) and Public Offering were used to fund the cash portion of the purchase price for the Will Energy acquisition and to reduce borrowings under the Company’s revolving credit facility then in effect.

In conjunction with the Public Offering, also on September 12, 2019, the Company entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million. On November 1, 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock, which resulted in net proceeds of approximately $21 million (the “Series B Private Placement”). Net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star acquisition.

Each of the series A and series B preferred shares are a new class of equity interests that rank equal to the common shares with respect to dividend rights and rights upon liquidation. The preferred shares will be entitled to vote on an as-converted basis on all matters submitted to a vote of the Company’s stockholders, with voting rights of the series A preferred shares equal to 19.99% of the common shares outstanding prior to the closing of the Public Offering and the series B preferred shares voting on an as-converted basis.Each series A preferred share and series B preferred share will then automatically convert into the number of common shares the purchaser would have received if the purchaser had purchased such common shares in the Public Offering and Series B Private Placement, respectively, for the same gross proceeds (the “Conversion”) and, upon the Conversion, the outstanding preferred shares will be cancelled. As of November 1, 2019, the Company has obtained approval of, or written agreements to approve, such increase in the number of authorized shares, and the issuance of the common shares underlying the series A preferred shares, from holders of a majority of the voting power of its capital stock, and will complete that process as soon as practicably possible. 

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Leases - Future Maturities (Details) $ in Thousands	Sep. 30, 2019 USD ($)
Operating lease maturities
2019 (remaining after September 30, 2019)	$ 170
2020	677
2021	324
2022	8
Total operating lease liability	1,179
Less: imputed interest	(57)
Present value of lease liabilities	1,122
Finance lease maturities
2019 (remaining after September 30, 2019)	6
2020	17
2021	18
2022	19
2023	20
2024	11
Total financing lease liability	91
Less: imputed interest	(14)
Present value of lease liabilities	$ 77

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	$ 3,134	$ 4,600
Commodity price contracts - liabilities	(24)	$ (422)
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	3,134
Commodity price contracts - liabilities	$ (24)

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Stock Based Compensation (NonOption) (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($) $ / shares shares	Sep. 30, 2018 USD ($) $ / shares shares
Stock-based compensation
Shares available for grant	1,200,000
Restricted Stock [Member]
Activity, shares
Canceled/Forfeited (in shares)	(63,909)	(152,294)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 2.91	$ 3.76
Stock-based compensation
Compensation expense not yet recognized | $	$ 1.2
Compensation expense, remaining weighted average vesting period	1 year 8 months 12 days
Value of issued stock | $	$ 1.1	$ 1.2
Weighted average forfeiture rate	0	0
Value of restricted shares forfeited | $	$ 0.3	$ 1.0
Stock-based compensation expense | $	$ 1.7	$ 3.2
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Activity, shares
Granted (in shares)	117,105	190,782
Canceled/Forfeited (in shares)	(49,773)	(182,227)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 6.42	$ 7.69
Stock-based compensation
Compensation expense not yet recognized | $	$ 1.0
Compensation expense, remaining weighted average vesting period	1 year 10 months 24 days
Target (as a percent)	100.00%
Stock-based compensation expense | $	$ 0.5	$ 0.6
Executive Officers and Employees [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Activity, shares
Granted (in shares)	307,650
Executive Officer [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Activity, shares
Granted (in shares)		225,782
Board of Directors [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year
Activity, shares
Granted (in shares)	80,410	82,500
Former President and CEO | Restricted Stock [Member]
Activity, shares
Canceled/Forfeited (in shares)		(105,800)
Former President and CEO | Performance Stock Units [Member]
Activity, shares
Canceled/Forfeited (in shares)		(153,127)
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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Income Taxes

9 Months Ended

Sep. 30, 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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Current tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total	$	30	$	(21)	$	484	$	288
Total tax provision (benefit):
Federal	$	—	$	—	$	—	$	—
State		30		(21)		484		288
Total income tax provision (benefit)	$	30	$	(21)	$	484	$	288

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the nine months ended September 30, 2019, the Company continued to take a full valuation allowance against its deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

Income tax expense relates to cash income taxes paid to the State of Louisiana on properties within the state that is not shielded by existing Federal tax attributes. 

In the quarter ended December 31, 2018, the Company experienced an Ownership Change (the “2018 Ownership Change”) as described in Internal Revenue Code (“IRC”) 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. 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 and expects it to be finalized in the fourth quarter of 2019.

In the quarter ended September 30, 2019, the Company issued 51.4 million additional shares of common stock pursuant to a follow-on equity offering (see Note 1 – “Organization and Business”). The cumulative effect of this equity offering, combined with other equity issuances, could have resulted in a subsequent Ownership Change, within the meaning of the IRC section 382. Based upon the information known to date, it is anticipated that if the Company experienced a subsequent Ownership Change, the IRC section 382 limit imposed by the Ownership Change could be more limiting on the ability of the Company to recover its NOLs than the 2018 Ownership Change. More specifically, the limit imposed by the subsequent Ownership Change could cause more of the Company’s NOLs to expire unused, resulting in a net impact to the Company’s effective tax rate and reported earnings. The Company is presently pursuing avenues set out in IRS guidance that allows the Company to inquire of (and rely upon) substantial shareholders as to the nature and timing of their purchases based on reliance of  “actual knowledge” (as defined in IRS guidance) to properly assess the effect of the stock issuances on its NOL recovery. The Company expects this analysis to be completed in the fourth quarter of 2019 and will record the effect (if any) on its NOLs in that period. 

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Leases

9 Months Ended

Sep. 30, 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 determines 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.

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 by 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 nine months ended September 30, 2019, the Company entered into a new office lease and new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company also entered into a new office equipment contract, which qualifies as a finance lease, during the nine months ended September 30, 2019. These leases do not have a material impact on the Company’s consolidated financial statements.

The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2019 (in thousands):

	September 30, 2019
Operating lease right of use asset - current (1)	$	690
Operating lease right of use asset - long-term (2)		489
Total operating lease right of use asset	$	1,179
Operating lease liability - current (3)	$	(690)
Operating lease liability - long-term (4)		(489)
Total operating lease liability	$	(1,179)
Financing lease right of use asset - current (1)	$	19
Financing lease right of use asset - long-term (2)		70
Total financing lease right of use asset	$	89
Financing lease liability - current (3)	$	(17)
Financing lease liability - long-term (4)		(74)
Financing lease liability - current	$	(91)

(1) Included in “Other current assets” on the consolidated balance sheet.

(2) Included in “Other non-current assets” on the consolidated balance sheet.

(3) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet.

(4) Included in “Other long-term liabilities” on the consolidated balance sheet.

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 table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2019:

	September 30, 2019
Weighted Average Remaining Lease Terms (in months):
Operating leases	21
Financing leases	57
Weighted Average Discount Rate:
Operating leases	5.31%
Financing leases	6.00%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2019, were as follows (in thousands):

	September 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after September 30, 2019)	$	170	$	6
2020		677		17
2021		324		18
2022		8		19
2023		-		20
2024		-		11
Total future minimum lease payments		1,179		91
Less: imputed interest		(57)		(14)
Present value of lease liabilities	$	1,122	$	77

The following table summarizes expenses related to the Company’s leases for the three and nine months ended September 30, 2019 (in thousands):

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1) (2)	$	138	$	609
Financing lease cost		5		5
Administrative lease cost (3)		19		56
Short-term lease cost (1) (4)		781		3,359
Total lease cost	$	943	$	4,029

(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 an office lease which expired on March 31, 2019 and a new office lease which began on April 1, 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 drilling rig and compressor agreements with lease terms of more than one month and less than one year.

There were $228 thousand and $4 thousand in cash payments related to operating leases and financing leases, respectively, during the nine months ended September 30, 2019.  

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Organization and Business (Details) $ in Thousands			1 Months Ended	3 Months Ended	9 Months Ended
	Nov. 01, 2019 USD ($) shares	Sep. 12, 2019 USD ($) shares	Oct. 31, 2019 item	Sep. 30, 2019 a shares	Sep. 30, 2019 USD ($) a item ft shares	Sep. 17, 2019 USD ($)	Jun. 14, 2019 shares	Jun. 13, 2019 shares
Common stock, shares authorized				100,000,000	100,000,000		100,000,000	50,000,000
Number of wells | item			2
Equity offering-common stock, shares				51,400,000
Net proceeds from equity offering | $					$ 53,650
Exaro Energy III LLC [Member]
Equity method investment, ownership percentage				37.00%	37.00%
Preferred Stock [Member]
Equity offering-common stock, shares	1,102,838	789,474
Net proceeds from equity offering | $	$ 21,000	$ 7,500
Voting rights of preferred stock (as a percent)		19.99%
Common Stock [Member]
Equity offering-common stock, shares		51,447,368		45,922,870
Treasury shares reissuance, shares		5,524,498		5,524,498
Net proceeds from equity offering | $		$ 46,200
Bullseye
Number of wells | item					14
Gross acres | a				17,400	17,400
Net acres | a				8,400	8,400
Gulf of Mexico [Member] | Maximum [Member]
Water depth of operations | ft					300
JPMorgan Chase Bank [Member]
Maximum borrowing capacity | $	$ 145,000					$ 65,000

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2019

Derivative Instruments [Abstract]

Schedule Of Derivative Contracts

As of September 30, 2019, the following financial derivative instruments were in place (fair value in thousands):

Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	Nov 2019 - Dec 2019	Swap	445,000	Mmbtus	$	2.62			(1)	$	180
Crude Oil	Oct 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(24)
Crude Oil	Oct 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	14
Crude Oil	Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	162
Crude Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	439
Crude Oil	Oct 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72			(3)	$	57
Crude Oil	Oct 2019 - Dec 2019	Swap	1,500	Bbls	$	57.67			(3)	$	17
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.841			(1)	$	341
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532			(1)	$	370
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.532			(1)	$	21
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.696			(1)	$	133
Crude Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74			(3)	$	720
Crude Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			(3)	$	623
Crude Oil	Jan 2020 - March 2020	Swap	2,700	Bbls	$	54.33			(3)	$	12
Crude Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33			(3)	$	20
Crude Oil	July 2020	Swap	5,500	Bbls	$	54.33			(3)	$	18
Crude Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33			(3)	$	26
Crude Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33			(3)	$	27
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.505			(1)	$	(82)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.505			(1)	$	90
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.505			(1)	$	3
Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.508			(1)	$	(76)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.508			(1)	$	94
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.508			(1)	$	3
		Total net fair value of derivative instruments								$	3,188

(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 September 30, 2019 (in thousands):

	Gross		Netting (1)		Total
Assets	$	3,134	$	—	$	3,134
Liabilities	$	(24)	$	—	$	(24)

(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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Crude oil contracts	$	500	$	(1,136)	$	1,442	$	(2,846)
Natural gas contracts		371		57		694		436
Realized gain (loss)	$	871	$	(1,079)	$	2,136	$	(2,410)
Crude oil contracts	$	1,049	$	(152)	$	(2,029)	$	(1,747)
Natural gas contracts		(39)		(88)		961		(804)
Unrealized gain (loss)	$	1,010	$	(240)	$	(1,068)	$	(2,551)
Gain (loss) on derivatives, net	$	1,881	$	(1,319)	$	1,068	$	(4,961)

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Acquisitions and Dispositions - Acquisitions (Details) $ in Thousands, shares in Millions			9 Months Ended
	Nov. 01, 2019 USD ($)	Oct. 25, 2019 USD ($) shares	Sep. 30, 2019 USD ($) a	Sep. 12, 2019 a
Will Energy [Member]
Acquisition
Gross acres | a				159,872
Acquisition consideration | $		$ 23,000
Cash consideration for acquisition | $		$ 14,750	$ 1,600
Equity issued for acquisition consideration (in shares) | shares		3.5
Will Energy [Member] | North Louisiana [Member]
Acquisition
Net acres | a				12,560
Will Energy [Member] | Western Anadarko Basin [Member]
Acquisition
Net acres | a				147,312
White Star [Member]
Acquisition
Net acres | a			315,000
Acquisition consideration | $	$ 132,500
Cash consideration for acquisition | $	$ 95,600		$ 12,500

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Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	3 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Accounts receivable:
Trade receivables	$ 4,463	$ 6,052
Receivable for Alta Resources Distribution	1,712	1,993
Joint interest billings	4,005	3,833
Income taxes receivable	878	424
Other receivables	1,054	223
Allowance for doubtful accounts	(994)	(994)
Total accounts receivable	11,118	11,531
Prepaid expenses and other:
Prepaid insurance	848	792
Other	147	511
Total prepaid expenses and other	995	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	12,704	17,986
Advances from partners	13,657	1,785
Accrued exploration and development	12,036	4,751
Accrued acquisition costs	3,763	4,352
Trade payables	12,441	3,385
Accrued general and administrative expenses	4,365	2,545
Accrued operating expenses	1,651	1,801
Other accounts payable and accrued liabilities	2,127	2,901
Total accounts payable and accrued liabilities	62,744	$ 39,506
Litigation Case Harris County [Member]
Accounts payable and accrued liabilities:
Loss contingency provision accrual increase	$ 2,100

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Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands, shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Current tax provision:
State	$ 30	$ (21)	$ 484	$ 288
Total	30	(21)	484	288
Total tax provision:
State	30	(21)	484	288
Income tax provision	$ 30	$ (21)	$ 484	$ 288
Annual carryover limitation					$ 2,400
Equity offering-common stock, shares	51.4