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~~June 30, ~~2017~~2019


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

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)


~~DELAWARE~~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 ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ 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. ~~(Check one):~~

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, 2017~~August 5, 2019 was ~~25,509,792~~34,434,406.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE ~~NINE~~SIX MONTHS ENDED ~~SEPTEMBER~~JUNE 30, ~~2017~~2019

TABLE OF CONTENTS


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016~~2018	3
	Consolidated Statements of Operations (unaudited) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	4
	Consolidated Statements of Cash Flows (unaudited) for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and 2018	6
	Notes to the ~~Unaudited~~ Consolidated Financial Statements (unaudited)	78
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3235
Item 4.	Controls and Procedures	3335

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	3336
Item 1A.	Risk Factors	3336
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3437
Item 3.	Defaults upon Senior Securities	3437
Item 4.	Mine Safety Disclosures	3438
Item 5.	Other Information	3438
Item 6.	Exhibits	3438

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

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Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)


	September 30,		December 31,		June 30,		December 31,
	2017		2016		2019		2018

	(unaudited)				(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	—	$	—
Accounts receivable, net		11,757		16,727		10,147		11,531
Prepaid expenses		1,786		1,787		1,005		1,303
Current derivative asset		440		—		2,149		4,600
Inventory		—		540
Other current assets						391		—
Total current assets		13,983		19,054		13,692		17,434
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		1,221,391		1,188,065		1,098,773		1,095,417
Unproved properties		38,720		38,338		44,003		34,612
Other property and equipment		1,272		1,265		1,331		1,314
Accumulated depreciation, depletion and amortization		(918,768)		(887,286)		(912,347)		(898,169)
Total property, plant and equipment, net		342,615		340,382		231,760		233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates		18,242		15,767		6,480		5,743
Other		954		1,311
Long-term derivative asset						244		—
Deferred tax asset						—		424
Other non-current assets						480		357
Total other non-current assets		19,196		17,078		7,204		6,524
TOTAL ASSETS	$	375,794	$	376,514	$	252,656	$	257,132

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	45,401	$	55,135	$	47,966	$	39,506
Current derivative liability		90		3,446		292		422
Current asset retirement obligations		4,008		4,308		826		1,329
Current portion of long-term debt						60,000		60,000
Total current liabilities		49,499		62,889		109,084		101,257
NON-CURRENT LIABILITIES:
Long-term debt		79,226		54,354		—		—
Asset retirement obligations		18,082		22,618		11,725		12,168
Other long term liabilities		248		248
Other long-term liabilities						3,677		3,318
Total non-current liabilities		97,556		77,220		15,402		15,486
Total liabilities		147,055		140,109		124,486		116,743
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 30,887,073 shares issued and 25,544,705 shares outstanding at September 30, 2017, 30,557,987 shares issued and 25,238,600 shares outstanding at December 31, 2016		1,224		1,211
Common stock, $0.04 par value, 100 million shares authorized, 39,967,341 shares issued and 34,442,843 shares outstanding at June 30, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018						1,587		1,573
Additional paid-in capital		300,986		296,439		341,563		339,981
Treasury shares at cost (5,342,368 shares at September 30, 2017 and 5,319,387 shares at December 31, 2016)		(128,482)		(128,321)
Retained earnings		55,011		67,076
Treasury shares at cost (5,524,498 shares at June 30, 2019 and 5,458,950 shares at December 31, 2018)						(129,266)		(129,030)
Retained deficit						(85,714)		(72,135)
Total shareholders’ equity		228,739		236,405		128,170		140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	375,794	$	376,514	$	252,656	$	257,132

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended				Nine Months Ended				Three Months Ended				Six Months Ended
	September 30,				September 30,				June 30,				June 30,
	2017		2016		2017		2016		2019		2018		2019		2018
	(unaudited)				(unaudited)				(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	6,109	$	4,946	$	18,134	$	17,164	$	7,439	$	9,607	$	13,845	$	18,418
Natural gas sales		9,681		12,011		31,956		31,283		3,857		5,848		9,499		14,457
Natural gas liquids sales		3,040		2,619		8,440		8,073		1,466		2,993		3,429		6,010
Total revenues		18,830		19,576		58,530		56,520		12,762		18,448		26,773		38,885
EXPENSES:
Operating expenses		7,041		8,158		20,203		22,782		5,694		6,478		10,886		13,405
Exploration expenses		315		444		690		1,088		249		394		473		863
Depreciation, depletion and amortization		11,193		15,166		35,678		49,586		7,573		9,498		15,129		19,983
Impairment and abandonment of oil and gas properties		84		1,165		1,515		4,268		1,247		777		1,834		4,104
General and administrative expenses		6,219		7,486		18,648		18,772		4,456		5,354		9,461		12,080
Total expenses		24,852		32,419		76,734		96,496		19,219		22,501		37,783		50,435
OTHER INCOME (EXPENSE):
Gain from investment in affiliates, net of income taxes		525		467		2,475		1,802
Gain (loss) from sale of assets		(184)		11		2,336		11
Gain (loss) from investment in affiliates, net of income taxes										427		(475)		457		232
Gain from sale of assets										421		1,370		409		10,817
Interest expense		(1,138)		(989)		(2,822)		(3,045)		(1,079)		(1,262)		(2,171)		(2,671)
Gain (loss) on derivatives, net		(9)		913		4,574		736		2,065		(2,610)		(813)		(3,642)
Other income (expense)		—		7		(27)		(303)
Other income										89		3		3		882
Total other income (expense)		(806)		409		6,536		(799)		1,923		(2,974)		(2,115)		5,618
NET LOSS BEFORE INCOME TAXES		(6,828)		(12,434)		(11,668)		(40,775)		(4,534)		(7,027)		(13,125)		(5,932)
Income tax provision		(88)		(51)		(397)		(410)		(427)		(151)		(454)		(309)
NET LOSS	$	(6,916)	$	(12,485)	$	(12,065)	$	(41,185)	$	(4,961)	$	(7,178)	$	(13,579)	$	(6,241)
NET LOSS PER SHARE:
Basic	$	(0.28)	$	(0.55)	$	(0.49)	$	(2.02)	$	(0.15)	$	(0.29)	$	(0.40)	$	(0.25)
Diluted	$	(0.28)	$	(0.55)	$	(0.49)	$	(2.02)	$	(0.15)	$	(0.29)	$	(0.40)	$	(0.25)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		24,708		22,881		24,662		20,370		33,909		24,933		33,840		24,863
Diluted		24,708		22,881		24,662		20,370		33,909		24,933		33,840		24,863

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Nine Months Ended				Six Months Ended
	September 30,				June 30,
	2017		2016		2019		2018

	(unaudited)				(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(12,065)	$	(41,185)	$	(13,579)	$	(6,241)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		35,678		49,586		15,129		19,983
Impairment of natural gas and oil properties		1,400		4,137		1,079		3,890
Exploration recovery		(232)		(2)
Deferred income taxes						424		—
Gain on sale of assets		(2,336)		(11)		(409)		(10,817)
Gain from investment in affiliates		(2,475)		(1,802)		(457)		(232)
Stock-based compensation		4,560		4,315		1,637		3,008
Unrealized loss (gain) on derivative instruments		(3,797)		2,400
Unrealized loss on derivative instruments						2,078		2,311
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables		4,767		7,026		1,530		2,132
Decrease (increase) in prepaids		1		(282)
Decrease in inventory		123		—
Decrease in accounts payable & advances from joint owners		(1,744)		(5,621)
Increase in other accrued liabilities		2,461		2,384
Decrease in income taxes receivable, net		—		2,868
Decrease in income taxes payable, net		(308)		(200)
Decrease in prepaids						298		352
Increase (decrease) in accounts payable & advances from joint owners						8,592		(2,027)
Decrease in other accrued liabilities						(350)		(2,618)
Increase in income taxes receivable, net						(424)		—
Increase (decrease) in income taxes payable, net						(258)		229
Other		72		(17)		(392)		3,293
Net cash provided by operating activities	$	26,105	$	23,596	$	14,898	$	13,263
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	$	(51,937)	$	(19,849)	$	(14,604)	$	(30,077)
Additions to furniture & equipment		(42)		—		(17)		—
Sale of furniture & equipment		12		11
Sale of oil & gas properties		1,151		—		—		21,562
Net cash used in investing activities	$	(50,816)	$	(19,838)	$	(14,621)	$	(8,515)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	172,015	$	118,310	$	73,548	$	130,677
Repayments under credit facility		(147,143)		(171,293)		(73,548)		(135,230)
Net proceeds from equity offering		—		50,451
Net costs from equity offering						(41)		—
Purchase of treasury stock		(161)		(230)		(236)		(195)
Debt issuance costs		—		(996)
Net cash provided by (used in) financing activities	$	24,711	$	(3,758)
Net cash used in financing activities					$	(277)	$	(4,748)
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	—	$	—	$	—	$	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—		—		—		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—	$	—	$	—	$	—

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the six months ended June 30, 2019

(in thousands, except number of shares)


				Additional						Total					Additional						Total
	Common Stock			Paid-in		Treasury		Retained		Shareholders’		Common Stock			Paid-in		Treasury		Retained		Shareholders’
	Shares	Amount		Capital		Stock		Earnings		Equity		Shares	Amount		Capital		Stock		Deficit		Equity
	(unaudited)											(unaudited)
Balance at December 31, 2016	25,238,600	$	1,211	$	296,439	$	(128,321)	$	67,076	$	236,405
Balance at December 31, 2018												34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering costs												—		—		(86)		—		—		(86)
Treasury shares at cost	(22,981)		—		—		(161)		—		(161)	(49,415)		—		—		(186)		—		(186)
Restricted shares activity	329,086		13		(13)		—		—		—	307,650		12		(12)		—		—		—
Stock-based compensation	—		—		4,560		—		—		4,560	—		—		1,052		—		—		1,052
Net income	—		—		—		—		(12,065)		(12,065)
Balance at September 30, 2017	25,544,705	$	1,224	$	300,986	$	(128,482)	$	55,011	$	228,739
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 costs												—		—		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

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the six months ended June 30, 2018

(in thousands, except number of shares)


				Additional						Total
	Common Stock			Paid-in		Treasury		Retained		Shareholders’
	Shares	Amount		Capital		Stock		Earnings (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

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore ~~properties in~~ Texas and Wyoming properties and to use that cash flow to explore, develop, exploit, ~~produce~~increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States. 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.

The following table lists the Company’s primary producing areas as of ~~September~~June 30, ~~2017:~~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)
~~Pecos County, Texas~~		~~Southern Delaware Basin (Wolfcamp)~~
~~Texas Gulf Coast~~		~~Conventional and unconventional formations~~
Zavala and Dimmit counties, Texas		Buda / ~~Austin Chalk~~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 ~~the three and nine months ended September 30, 2017.~~all periods shown in this report.

~~In July~~Since 2016, the Company purchased approximately 12,100 gross operated undeveloped acres (5,000 net acres) in the Southern Delaware Basin in Pecos County, Texas, which it began drilling during the fourth quarter of 2016, and as of September 30, 2017, had increased its acreage to approximately 13,600 gross operated acres (6,800 net).

~~The Company’s 2017 capital program~~ has been focused ~~and will continue to focus,~~ on the development of ~~the Company’s~~its Southern Delaware Basin ~~acreage. Additionally,~~acreage in Pecos County, Texas, which is expected to continue to generate positive returns in the current price environment. As of June 30, 2019, the Company was producing from twelve wells over its approximate 17,000 gross operated (8,100 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

The Company currently expects this acreage in West Texas to be the primary focus of its drilling program for the remainder of 2019. Until a sustained improvement in commodity prices occurs, the Company will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas. The Company will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales. During this time, the Company will continue to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, ~~maintain core leases and identify~~while also searching for new resource ~~potential~~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 ~~internally~~ and where ~~appropriate, through acquisition. The~~it can develop an inventory of additional drilling prospects that the Company believes will ~~continuously monitor the commodity price environment, including its stability~~enable it to economically grow production and ~~forecast, and, if warranted, make adjustments to its strategy as the year progresses.~~add reserves.

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, ~~2016 (the “2016~~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 ~~2016~~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.

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Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the ~~2016~~2018 Form 10-K. ~~The~~These unaudited interim consolidated results of operations for the ~~three and nine~~six months ended ~~September~~June 30, ~~2017~~2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, ~~2017.~~2019.

~~Table of Contents~~

The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by ~~our~~the Company’s wholly owned subsidiary, Contaro Company, ~~(“Contaro”)~~ is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results ~~reserves~~ or production in those reported for the Company’s consolidated ~~results.~~results of operations.

Liquidity and Going Concern

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

Oil and Gas Properties - Successful Efforts

~~Our~~The Company’s application of the successful efforts method of accounting for ~~our~~its natural gas and oil exploration and production activities requires ~~judgments~~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,

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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 ~~probable~~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. ~~The Company recognized no impairment of proved properties for~~During the ~~three and nine~~six months ended ~~September~~June 30, ~~2017. No impairment of proved properties was recognized for the three months ended September 30, 2016, and~~2019, the Company recognized ~~approximately $0.7~~$0.2 million in non-cash proved property impairment ~~of proved properties for~~related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the ~~nine~~quarter ended December 31, 2018. During the six months ended ~~September~~June 30, ~~2016, substantially all~~2018, the Company recognized $2.7 million in non-cash proved property impairment charges, $2.3 million of which ~~was directly~~ related to ~~the decline in commodity prices~~its Vermilion 170 offshore property and ~~the resulting impact on estimated future net cash flows from associated reserves.~~$0.4 million of which related to non-core onshore properties due to revised reserve estimates. The Vermilion 170 offshore property was subsequently sold effective December 1, 2018

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized no impairment of unproved properties for the three months ended September 30, 2017 and $1.4 million in impairment expense related to the partial impairment of two unused offshore platforms for the nine months ended September 30, 2017. The Company recognizednon-cash impairment expense of approximately ~~$1.1~~$0.4 million and approximately ~~$3.4~~$0.9 million for ~~the~~ three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2019, respectively, related to ~~partial~~ impairment of certain unproved properties primarily due ~~primarily~~ to ~~the sustained low commodity price environment~~expiring leases. The Company recognized non-cash impairment expense of approximately $0.4 million and ~~expiring leases, substantially all of which was~~approximately $1.2 million for three and six months ended June 30, 2018, respectively, related to impairment of certain non-core unproved ~~lease cost amortization of marginal, non-core~~ properties ~~in Fayette and Gonzales counties, Texas.~~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~~performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and six months ended ~~September~~June 30, ~~2017,~~2019, the Company excluded ~~971,813~~648,170 shares or units and 561,164 shares or units, respectively, of potentially dilutive securities, as they were ~~antidilutive,~~antidilutive. For the three and six months ended June 30, 2018, the Company excluded ~~813,151~~1,628,321 shares or units and 1,713,673 shares or units, respectively, of potentially dilutive securities, ~~for the nine months ended September 30, 2017, as they were antidilutive.~~

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For the three months ended September 30, 2016, the Company excluded 439,017 potentially dilutive securities, as they were antidilutive, and 382,867 potentially dilutive securities were excluded for the nine months ended September 30, 2016, as they were antidilutive.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a 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. ~~Finally, the~~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

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transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

Revenue from Contracts with Customers

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

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

Transaction Price Allocated to Remaining Performance Obligations

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

Contract Balances

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

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the 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 six months ended June 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

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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 ~~January 2017,~~August 2018, the ~~Financial Accounting Standards Board~~FASB issued ASU 2018-13 – Fair Value Measurement (“~~FASB”~~Topic 820”) ~~issued Accounting Standards Update (“ASU”) No. 2017-01: Business Combinations (Topic 805) Clarifying~~. The amendments in ASU 2018-13 modify the ~~Definition of a Business (ASU 2017-01).~~disclosure requirements on fair value measurements in Topic 820. The amendments in this update are ~~intended to clarify the definition of a business with the objective of adding guidance to assist~~effective for all entities ~~with evaluating whether transactions should be accounted~~ for ~~as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill,~~fiscal years, and ~~consolidation. Public business entities should apply the amendments in this update to annual~~interim periods within those fiscal years, beginning after December 15, ~~2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition.~~2019. The provisions of this ~~accounting~~ update are not expected to have a material impact on the Company’s financial position or results of operations.

In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows.

In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows.

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In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its initial review of all revenue contracts. The Company’s revenue contracts are normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard.

3. Acquisitions and Dispositions

~~In July 2016,~~On March 28, 2018, the Company purchased one-half of the seller’s interest in approximately 12,100 gross undeveloped acres (approximately 5,000 net acres) in the Southern Delaware Basin of Texas for up to $25 million (the “Acquisition”). The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million to be paid in the form of carried well costs expected to be paid over the period of drilling and completion of the first six wells. Additionally, contingent upon success, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which would increase the total consideration paid by the Company to $25 million. As of September 30, 2017, the Company had paid all $10 million of the carried well costs and $0.7 million in spud bonuses. As of September 30, 2017, the Company had increased its acreage to approximately 13,600 gross operated acres (6,800 net).

On December 30, 2016, all of the Company’s non-core Colorado assets were sold to an independent oil and gas company for an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The properties consisted of the Company’s approximately 16,000 gross (11,200 net) acres primarily in Adams and Weld counties, Colorado and associated producing vertical wells.

~~Effective February 1, 2017, the~~ Company sold ~~to a third party all of its assets in the North Bob West area and~~ its operated Eagle Ford Shale assets ~~in the Escobas area, both~~ located in ~~Southeast~~Karnes County, Texas for a cash purchase price of ~~$650,000.~~$21.0 million. The Company recorded a net gain of ~~$2.9~~$9.4 million, prior to 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 $1.4 million after removal of the asset retirement obligations associated with the sold properties.

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.

4. Fair Value Measurements

Pursuant to Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures ~~(ASC 820)~~(“ASC 820”), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

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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~~June 30, ~~2017.~~2019. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Fair value information for financial assets and liabilities was as follows as of ~~September~~June 30, ~~2017~~2019 (in thousands):


	Total		Fair Value Measurements Using						Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3		Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	440	$	—	$	440	$	—	$	2,393	$	—	$	2,393	$	—
Commodity price contracts - liabilities	$	(90)	$	—	$	(90)	$	—	$	(292)	$	—	$	(292)	$	—

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

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Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in ~~the Company's~~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 ~~the Company~~ reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted ~~markets~~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~~June 30, ~~2017,~~2019, the Company's derivative contracts were all with ~~certain members of its credit facility lenders which are~~ major ~~financial~~ institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Estimates of the fair value of financial instruments are made in accordance with the requirements of ~~ASC~~Accounting Standards Codification Topic 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's ~~credit facility with the Royal Bank of Canada and other lenders (the “RBC~~ Credit ~~Facility”)~~Facility approximates carrying value because the facility interest rate approximates current market rates and is reset at least every ~~six months.~~quarter. See Note 910 - ~~"Long-Term Debt"~~"Indebtedness" for further information.

Impairments

~~Contango~~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 ~~probable~~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

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used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

5. Derivative Instruments

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

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As of ~~September~~June 30, ~~2017,~~2019, the Company’s natural gas and oil derivative positions consisted of ~~“swaps”~~swaps and ~~“costless collars”.~~costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the ~~RBC~~ Credit ~~Facility.~~Facility or under unsecured lines of credit with non-bank counterparties. See Note ~~9 - "Long-Term Debt"~~10 – “Indebtedness” for further information regarding the ~~RBC~~ Credit Facility.

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

~~The~~As of June 30, 2019, the following financial derivative instruments were in place ~~at September 30, 2017~~ (fair value in thousands):



Commodity	Period	Derivative	Volume/Month	Price/Unit (1)		Fair Value		Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	Oct 2017	Collar	200,000 MMBtu	$	2.65 - 3.00		0	July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	278
Natural Gas	Nov 2017 - Dec 2017	Collar	400,000 MMBtu	$	2.65 - 3.00		(90)

Natural Gas	Oct 2017	Swap	70,000 MMBtu	$	3.51		37	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	136
Natural Gas	Nov 2017 - Dec 2017	Swap	300,000 MMBtu	$	3.51		246	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	267

Oil	Oct 2017	Swap	6,000 Bbls	$	53.95		13	July 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(237)
Oil	Nov 2017 - Dec 2017	Swap	8,000 Bbls	$	53.95		30	July 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(33)

Oil	Oct 2017 - Dec 2017	Swap	9,000 Bbls	$	56.20		114	July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	46
		Total net fair value of derivative instruments				$	350
Oil								July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	163
Oil								Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	370
Oil								Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	340

Oil								July 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72			(3)	$	51

Natural Gas								Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.84			(1)	$	225

Natural Gas								April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53			(1)	$	167
Natural Gas								Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.53			(1)	$	5

Natural Gas								Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.70			(1)	$	38

Oil								Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74			(3)	$	148
Oil								July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			(3)	$	221

									Total net fair value of derivative instruments								$	2,185

(1) ~~Commodity price derivatives are based~~Based on Henry Hub NYMEX natural gas ~~prices and~~prices.

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

(3) Based on West Texas Intermediate crude oil ~~prices, as applicable.~~prices.

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI - Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000

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barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in a liability position of $84 thousand as of June 30, 2019.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of ~~September~~June 30, ~~2017~~2019 (in thousands):


	Gross		Netting (1)		Total		Gross		Netting (1)		Total
Assets	$	440	$	—	$	440	$	2,393	$	—	$	2,393
Liabilities	$	(90)	$	—	$	(90)	$	(292)	$	—	$	(292)

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

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, ~~2016~~2018 (in thousands):


	Gross		Netting (1)		Total		Gross		Netting (1)		Total
Assets	$	—	$	—	$	—	$	4,600	$	—	$	4,600
Liabilities	$	(3,446)	$	—	$	(3,446)	$	(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~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2019		2018		2019		2018
Crude oil contracts	$	342	$	—	$	879	$	—	$	286	$	(1,123)	$	941	$	(1,711)
Natural gas contracts		179		(619)		(102)		3,136		211		305		324		380
Realized gain (loss)	$	521	$	(619)	$	777	$	3,136	$	497	$	(818)	$	1,265	$	(1,331)

Crude oil contracts	$	(661)	$	—	$	156	$	—	$	365	$	(1,311)	$	(3,077)	$	(1,594)
Natural gas contracts		131		1,532		3,641		(2,400)		1,203		(481)		999		(717)
Unrealized gain (loss)	$	(530)	$	1,532	$	3,797	$	(2,400)	$	1,568	$	(1,792)	$	(2,078)	$	(2,311)
Gain (loss) on derivatives, net	$	(9)	$	913	$	4,574	$	736	$	2,065	$	(2,610)	$	(813)	$	(3,642)

~~In October 2017, the Company entered into the following additional financial derivative contracts with a member of its credit facility lenders:~~

Commodity

Period

Derivative

Volume/Month

Price/Unit (1)
Natural Gas

Jan 2018 - July 2018

Swap

370,000 MMBtu

$
3.07
Natural Gas

Aug 2018 - Oct 2018

Swap

70,000 MMBtu

$
3.07
Natural Gas

Nov 2018 - Dec 2018

Swap

320,000 MMBtu

$
3.07

Oil

Jan 2018 - June 2018

Swap

20,000 Bbls

$
56.40
Oil

July 2018 - Oct 2018

Collar

20,000 Bbls

$
52.00 - 56.85
Oil

Nov 2018 - Dec 2018

Collar

15,000 Bbls

$
52.00 - 56.85

Oil

Jan 2019 - Dec 2019

Collar

7,000 Bbls

$
50.00 - 58.00

~~(1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and Argus Louisiana Light Sweet oil prices, as applicable.~~

6. Stock-Based Compensation

The Company recognized approximately $4.6 million and $4.3 million in stock compensation expense during the nine months ended September 30, 2017 and 2016, respectively, for equity awards granted to its officers, employees and directors. As of September 30, 2017, an additional $6.2 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 2.1 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options.

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Restricted Stock

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, the Company granted ~~383,376~~307,650 shares of restricted common stock, which vest over three years, to ~~new~~employees and ~~existing employees~~executive officers as part of their overall compensation ~~package, and 74,325~~package. Additionally, during the six months ended June 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 ~~intrinsic~~fair value of the restricted shares granted during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, was ~~$7.55~~$2.91 per share, with a total fair value of approximately ~~$3.5~~$1.1 million ~~after~~and no adjustment for an estimated weighted average forfeiture ~~rate of 5.7%.~~rate. During the ~~nine~~six months ended ~~September~~June 30, ~~2017, 128,615~~2019, 38,161 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~$1.3~~$0.2 million. The Company recognized approximately $1.4 million in restricted stock compensation expense during the six months ended June 30, 2019 related to restricted stock granted to its officers, employees and directors. As of June 30, 2019, an additional $1.6 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.8 years. Approximately ~~1.6~~1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of ~~September~~June 30, ~~2017,~~2019, assuming PSUs (as defined below) are settled at 100% of target.

During the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018, the Company granted 40,876 immediately vested shares of restricted common stock. Of these, 38,943 shares were granted to employees and 1,933 shares were granted to directors, all of which were issued pursuant to the Company’s salary replacement program (the “Salary Replacement Program”) which temporarily deferred 10% of 2015 employee salaries and director fees. Additionally, the Company granted 197,306225,782 shares of restricted common stock, which vest over three years, to ~~employees~~executive officers as part of their overall compensation ~~package, which vest over four years, and 49,460~~package. Additionally, during the

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six months ended June 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, which vest over one year.~~Plan. The weighted average fair value of the restricted shares granted during the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018, was ~~$11.60~~$3.76 per share, with a total fair value of approximately ~~$3.3~~$1.2 million ~~after~~and no adjustment for an estimated weighted average forfeiture ~~rate of 3.5%.~~rate. During the ~~nine~~six months ended ~~September~~June 30, ~~2016, 4,160~~2018, 24,980 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018 was approximately ~~$130 thousand.~~$0.2 million. The Company recognized approximately $1.8 million in restricted stock compensation expense during the six months ended June 30, 2018 related to restricted stock granted to its officers, employees and directors.

Performance Stock Units

During the nine months ended September 30, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2017, 94,063 PSUs were forfeited by former employees. No PSUs were issued or forfeited during the nine months ended September 30, 2016. PSUsPerformance 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 ~~awarded~~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 six months ended June 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 six months ended June 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 $0.3 million in stock compensation expense related to PSUs during the six months ended June 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 June 30, 2019, an additional $1.4 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.0 years.

During the six months ended June 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 six months ended June 30, 2018, 19,300 PSUs were forfeited by former employees. The Company recognized approximately $1.2 million in stock compensation expense related to PSUs during the six months ended June 30, 2018.

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016,~~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~~six months ended ~~September~~June 30, ~~2017~~2019 or ~~2016.~~2018.

During the six months ended June 30, 2019, no stock options were exercised and stock options for 12,052 shares were forfeited by former employees. During the six months ended June 30, 2018, no stock options were exercised or forfeited.

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7. Leases

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

ASC 842 contains several optional practical expedients upon adoption, one of which is referred to as the “package of three practical expedients”. The expedients must be taken together and allow entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Company elected to apply this practical expedient package to all of its leases upon adoption. The Company also chose to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. ASC 842 provides for a modified retrospective transition approach requiring lessees to recognize and measure leases on the balance sheet at the beginning of either the earliest period presented or as of the beginning of the period of adoption. The Company elected to apply ASC 842 as of the beginning of the period of adoption (January 1, 2019) and will not restate comparative periods. For new leases, the Company 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~~six months ended ~~September~~June 30, ~~2017, no stock options were exercised, while 17,072 stock options were forfeited by former employees. During~~2019, the ~~nine~~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 six months ended ~~September~~June 30, ~~2016, no stock options were exercised~~2019. These leases do not have a material impact on the Company’ consolidated financial statements.

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


	June 30, 2019
Operating lease right of use asset - current (1)	$	374
Operating lease right of use asset - long-term (2)		291
Total operating lease right of use asset	$	665

Operating lease liability - current (3)	$	(374)
Operating lease liability - long-term (4)		(291)
Total operating lease liability	$	(665)

Financing lease right of use asset - current (1)	$	17
Financing lease right of use asset - long-term (2)		69
Total financing lease right of use asset	$	86

Financing lease liability - current (3)	$	(15)
Financing lease liability - long-term (4)		(71)
Financing lease liability - current	$	(86)

(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.

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The Company's leases generally do not provide an implicit rate, and ~~stock options~~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 ~~1,657 shares of common stock were forfeited.~~the remaining lease term.

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


		June 30, 2019
Weighted Average Remaining Lease Terms (in months):
Operating leases		22.2
Financing leases		60.0

Weighted Average Discount Rate:
Operating leases		6%
Financing leases		6%

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


	June 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after June 30, 2019)	$	184	$	8
2020		358		16
2021		114		17
2022		9		18
2023		-		18
2024		-		9
Total future minimum lease payments		665		86
Less: imputed interest		(38)		(14)
Present value of lease liabilities	$	627	$	72

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


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost (1) (2)	$	100	$	471
Financing lease cost		-		-
Administrative lease cost (3)		18		37
Short-term lease cost (1) (4)		2,068		2,578
Total lease cost	$	2,186	$	3,086

(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 $0.1 million in cash payments related to operating leases during the six months ended June 30, 2019. No cash payments were made for the financing lease during the six months ended June 30, 2019.

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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, 2017		December 31, 2016		June 30, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	7,262	$	8,424	$	3,370	$	6,052
Receivable for Alta Resources Distribution		1,993		1,993
Receivable for Alta Resources distribution						1,712		1,993
Joint interest billings		2,972		3,519		4,205		3,833
Income taxes receivable		92		91		848		424
Other receivables		335		3,395		1,006		223
Allowance for doubtful accounts		(897)		(695)		(994)		(994)
Total accounts receivable	$	11,757	$	16,727	$	10,147	$	11,531

Prepaid expenses and other:
Prepaid insurance	$	1,088	$	1,086	$	794	$	792
Other		698		701		211	��	511
Total prepaid expenses and other	$	1,786	$	1,787	$	1,005	$	1,303

Accounts payable and accrued liabilities:
Royalties and revenue payable	$	19,343	$	16,920	$	12,580	$	17,986
Advances from partners		3,230		5,792		7,693		1,785
Accrued exploration and development		8,189		11,176		5,226		4,751
Accrued carried well costs		—		7,155
Accrued acquisition costs						3,763		4,352
Trade payables		5,433		5,406		12,185		3,385
Accrued LOE & workover expense		2,228		1,867
Accrued G&A and legal expense		3,997		5,016
Accrued general and administrative expenses						2,499		2,545
Accrued operating expenses						2,144		1,801
Other accounts payable and accrued liabilities		2,981		1,803		1,876		2,901
Total accounts payable and accrued liabilities	$	45,401	$	55,135	$	47,966	$	39,506

Included in the table below isare supplemental ~~information about certain~~ cash flow disclosures and non-cash ~~transactions~~investing activities during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 (in thousands):


		Nine Months Ended September 30,				Six Months Ended June 30,
		2017		2016		2019		2018
Cash payments:
Interest payments	$	2,501	$	2,935	$	2,157	$	2,596
Income tax payments (refunds)	$	708	$	(2,337)
Income tax payments					$	805	$	81
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	(10,142)	$	7,248	$	475	$	(229)

8.9. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%.

~~Table of Contents~~

The following table (in thousands) presents condensed balance sheet data for Exaro as of September 30, 2017 and December 31, 2016. The balance sheet data was derived from Exaro’s balance sheet as of September 30, 2017 and December 31, 2016 and was not adjusted to represent the Company’s percentage of ownership interest in Exaro. The Company’s share in the equity of Exaro at ~~September~~June 30, ~~2017~~2019 was approximately ~~$18.1~~$6.5 million.

September 30, 2017

December 31, 2016

Current assets (1)

$
15,897

$
25,296

Non-current assets:

Net property and equipment

84,766

90,621

Gas processing deposit

1,150

1,150

Other non-current assets

57

8

Total non-current assets

85,973

91,779

Total assets

$
101,870

$
117,075

Current liabilities (2)

$
3,950

$
65,694

Non-current liabilities:

Long-term debt

44,356

—

Other non-current liabilities

3,466

8,106

Total non-current liabilities

47,822

8,106

Members' equity

50,098

43,275

Total liabilities & members' equity

$
101,870

$
117,075

~~(1)~~

~~Approximately $13.6 million and $19.6 million of current assets as of September 30, 2017 and December 31, 2016, respectively, is cash.~~

~~(2)~~

~~Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced.~~

The ~~following table (in thousands) presents~~Company accounts for its ownership in Exaro using the ~~condensed~~equity method of accounting, and therefore, does not include its share of individual operating results ~~of operations for Exaro~~or production in those reported for the three and nine months ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 2017 and 2016 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ~~ownership interest but rather reflects the results of Exaro as a company.~~ consolidated results.

The Company’s share in Exaro’s results of operations recognized for the three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 was a gain of $0.4 million, net of no tax expense, and a loss of $0.5 million, net of no tax ~~expense.~~expense, respectively. The Company’s share in Exaro’s results of operations recognized for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 was a gain of ~~$2.5~~$0.7 million, net of no tax expense, and a gain of ~~$1.8~~$0.2 million, net of no tax expense, respectively.

Three Months Ended September 30,

Nine Months Ended September 30,


2017

2016

2017

2016

Production:

Oil (thousand barrels)

24

30

77

98

Gas (million cubic feet)

2,216

2,659

6,797

8,083

Total (million cubic feet equivalent)

2,360

2,839

7,260

8,671

Oil and natural gas sales

$
7,483

$
8,242

$
24,499

$
20,730

Gain (loss) on derivatives

318

1,011

3,720

(1,231)

Other gain

—

—

—

10,441

Less:

Lease operating expenses

2,928

3,969

10,914

11,513

Depreciation, depletion, amortization & accretion

2,143

2,880

6,734

8,705

General & administrative expense

701

671

2,308

2,605

Income from continuing operations

2,029

1,733

8,263

7,117

Net interest expense

(629)

(598)

(1,582)

(1,994)

Net income

$
1,400

$
1,135

$
6,681

$
5,123

~~Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes.~~

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~~9. Long-Term Debt~~10. Indebtedness

~~RBC~~ Credit Facility

~~In October 2013, the Company entered into a~~The Company’s $500 million revolving credit facility with Royal Bank of Canada and other lenders (the ~~“RBC Credit~~“Credit Facility”)~~, which~~ currently matures on October 1, 2019. On June 17, 2019, the Company entered into the Seventh Amendment to the Credit Facility (the “Seventh Amendment”). The Seventh Amendment redetermined the borrowing base at $85 million pursuant to the regularly scheduled redetermination process, with a current availability limit of $75 million. The Seventh Amendment also set the next borrowing base redetermination to August 1, 2019. The borrowing base under the facility is redetermined each November and May. The Company is currently going through the redetermination process, but does not expect a material reduction that would affect its liquidity. As of September 30, 2017, the borrowing base under the RBC Credit Facility ~~was $125 million.~~effective August 1, 2019 has not yet been determined.

As of ~~September~~June 30, ~~2017,~~2019 and December 31, 2018, the Company had approximately ~~$79.2~~$60.0 million outstanding under the ~~RBC~~ Credit Facility and $1.9 million in an outstanding ~~letters~~letter of credit. As of ~~December 31, 2016, the Company had approximately $54.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of September~~June 30, ~~2017,~~2019, borrowing availability under the ~~RBC~~ Credit Facility was ~~$43.9~~$13.1 million.

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

Total interest expense under the ~~RBC~~ Credit Facility, including commitment fees, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was approximately $1.1 million and ~~$2.8~~$2.2 million, respectively. Total interest expense under the ~~RBC~~ Credit Facility, including commitment fees, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018 was approximately ~~$1.0~~$1.3 million and ~~$3.0~~$2.7 million, respectively.

The ~~RBC~~weighted average interest rate in effect at June 30, 2019 and December 31, 2018 was 5.9% and 6.3%, respectively.

The Credit Facility contains restrictive covenants which, among other things, ~~restrict the declaration or payment of dividends by Contango and~~ require a Current Ratio of greater than or equal to ~~1.0~~1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the ~~RBC Credit Facility Agreement. As of September 30, 2017, the Company was in compliance with all financial covenants under the RBC~~ Credit Facility. The ~~RBC~~ Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of June 30, 2019, the Company was in compliance with all but the Current Ratio covenant under the Credit Facility, and the Company obtained a waiver for such non-compliance effective June 30, 2019.

~~The weighted average interest rate~~Pursuit of Refinancing and Other Liquidity-Enhancing Initiatives

Over the past several months, the Company has been in ~~effect at September 30, 2017~~discussions with its current lenders and ~~December 31, 2016 was 4.9% and 4.2%, respectively. The RBC~~other sources of capital regarding a possible refinancing and/or replacement of its existing Credit Facility, which matures on October 1, ~~2019,~~2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at ~~which time~~all, or provide any ~~outstanding balances will~~specific amount of additional liquidity, and in such case there is substantial doubt that the Company could continue as a going concern. The refinancing and/or replacement of the Credit Facility could be ~~due.~~made in conjunction with a substantial acquisition or disposition, an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended Credit Facility that would be expected to provide additional borrowing capacity for future capital expenditures. While the Company reviews such liquidity-enhancing alternative sources of capital, it intends to continue to minimize its drilling program capital expenditures and acquisitions in the Southern Delaware Basin and pursue a reduction in its borrowings under the Credit Facility, including through a reduction in cash general and administrative expenses and the possible sale of additional non-core properties.

~~10.~~

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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,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2019		2018		2019		2018
Current tax provision:
Federal	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
State		88		51		397		410		427		151		454		309
Total	$	88	$	51	$	397	$	410	$	427	$	151	$	454	$	309
Total tax provision:
Federal	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
State		88		51		397		410		427		151		454		309
Total	$	88	$	51	$	397	$	410
Included in gain from investment in affiliates	$	—	$	—	$	—	$	—
Total income tax provision	$	88	$	51	$	397	$	410	$	427	$	151	$	454	$	309

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~~six months ended ~~September~~June 30, ~~2017,~~2019, the Company ~~continues~~continued to ~~fully value the~~record a full valuation allowance against its net deferred tax ~~asset.~~assets. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

~~Table~~Income tax expense relates to current income taxes paid, or expected to be paid, to the State of ~~Contents~~

~~11. Related Party Transactions~~

~~Olympic Energy Partners~~

~~Mr. Joseph J. Romano,~~Louisiana on income from properties within the ~~Chairman of the Company’s board of directors,~~state that is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). Olympic participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to our Dutch and Mary Rose wells.

During the three and nine months ended September 30, 2017, Mr. Romano earned $15 thousand and $42 thousand for his service as a director of the Company, respectively. During the three and nine months ended September 30, 2016, Mr. Romano earned $17 thousand and $43 thousand for his service as a director of the Company, respectively.not shielded by existing Federal tax attributes.

In May 2017, Mr. Romano received 14,865 shares of restricted stock, which vest in one year, as part of his board of director compensation. The Company recognized compensation expense of approximately $28 thousand and $90 thousand related to the ~~shares granted to Mr. Romano for the three and nine months~~quarter ended September 30, 2017, respectively. In January 2016, Mr. Romano received 261 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program and an additional 9,892 shares of restricted stock in May 2016, which vest in one year, as part of his board of director compensation. During the three and nine months ended September 30, 2016,December 31, 2018, the Company ~~recognized compensation expense of approximately $30 thousand and $70 thousand, respectively, related to the shares granted to Mr. Romano.~~

~~Below is a summary of payments received from (paid to) Olympic~~experienced an Ownership Change as described in the ordinary course of business in the Company’s capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands):

Three Months Ended September 30,

Nine Months Ended September 30,


2017

2016

2017

2016
Revenue payments as well owners

$
(634)

$
(617)

$
(2,071)

$
(1,788)

Joint interest billing receipts

111

149

306

272

~~As of September 30, 2017 and December 31, 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands):~~

September 30, 2017

December 31, 2016

Accounts receivable:

Joint interest billing

$
26

$
59

Accounts payable:

Royalties and revenue payable

(448)

(557)

~~Oaktree Capital Management L.P.~~

As of September 30, 2017, Oaktree Capital Management L.P. ("Oaktree"), through various funds, owned approximately 5.1% of the Company's stock. On October 1, 2013, Mr. James Ford, then a Managing Director and Portfolio Manager within Oaktree, was elected to the Company's board of directors. Mr. Ford is currently a Senior Advisor to Oaktree.

Historically, all cash and equity awards payable to Mr. Ford were instead granted to an affiliate of Oaktree. Beginning in October 2016, all cash and equity awards payable to Oaktree for Mr. Ford’s service as a director became payable to him directly. During the three and nine months ended September 30, 2017, Mr. Ford earned $18 thousand and $50 thousand in cashInternal Revenue Code section 382 as a result of ~~his board participation, respectively. During the three and nine months ended September 30, 2016, an affiliate of Oaktree earned $18 thousand and $50 thousand in cash~~a completed follow-on equity offering. Management estimates that as a result of ~~Mr. Ford's board participation, respectively.~~

~~Table~~this Ownership Change, its future Net Operating Loss (“NOL”) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year, plus the amount of ~~Contents~~

~~In May 2017, Mr. Ford received 14,865 shares~~any built in gains (essentially: the excess of ~~restricted stock, which vest~~the fair market value of properties over their respective income tax bases) recognized in ~~one year, as part~~the five years after 2018. As a result of ~~his board~~these limitations, it is likely that a substantial portion of ~~director compensation.~~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 ~~recognized compensation expense of approximately $28 thousand and $90 thousand~~is performing additional analysis related to ~~the shares granted to Mr. Ford for the three and nine months ended September 30, 2017, respectively. In January 2016, an affiliate of Oaktree received 313 shares of restricted stock,~~this matter which vested immediately, pursuant to the Salary Replacement Program and an additional 9,892 shares of restricted stock in May 2016, which vest in one year, as part of Mr. Ford’s board of director compensation. During the three and nine months ended September 30, 2016,will be finalized when the Company ~~recognized compensation expense of approximately $30 thousand and $70 thousand, respectively, related to the shares granted to an affiliate of Oaktree.~~files its 2018 U.S. federal income tax return later this year.

12. Commitments and Contingencies

Legal Proceedings

From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.

In July 2010, several parties associated with a limited partnership, formed to invest in oil and gas properties, that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The plaintiffs’ expert has provided a range of estimated monetary damages of up to approximately $9.4 million as to the Company’s subsidiary. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses.

In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company ~~is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing~~appealed the trial court’s decision to the applicable state Court of ~~Appeals.~~Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company continues to vigorously defend this lawsuit and has filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. The Company is awaiting a response from the Texas Supreme Court

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as to whether it intends to review the case. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals’ ruling.

In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in ~~district court~~the District Court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the ~~district court~~District Court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million, although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The trial court also awarded the Company a judgement against the plaintiff ~~is appealing~~for approximately $1.0 million for reimbursement of legal fees. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. In December 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The ~~Company is vigorously defending this lawsuit and believes~~plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff filed a petition requesting that ~~it has meritorious defenses. The Company believes if this~~the matter ~~were to~~ be ~~determined adversely, amounts owed to~~reviewed by the ~~plaintiff could be partially offset by recoupment rights~~Texas Supreme Court. In June 2019, the Company ~~may have against other working interest and/or royalty interest owners in~~received notice that the ~~unit.~~plaintiff’s petition would be denied.

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.

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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~~third-party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. ~~The~~Beginning in late 2016, the Company ~~currently forecasts that~~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.~~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 $0.5 million during each of the six months ended June 30, 2019 and 2018. As of June 30, 2019, the Company estimates that the remaining net deficiency fee will be approximately ~~$1.0~~$0.7 million ~~annually for~~through the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. As of September 30, 2017, based upon the current commodity price market and our short term strategic drilling plans, the Company has recorded a $0.8 million loss contingency through December 31, 2017. The Company will continue to assess this commitment in light of its development plans for this area.

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~~Available Information~~

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”). 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~~expiration of the ~~Securities Act~~contract on March 31, 2020, all of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K and those factors summarized below:

our ability to successfully develop our acquisition of undeveloped acreage in the Southern Delaware Basin, integrate the operations relating thereto with our existing operations and realize the benefits of such acquisition;

~~our financial position;~~

~~our business strategy, including outsourcing;~~

~~meeting our forecasts and budgets;~~

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

~~natural gas and oil price volatility;~~

~~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 operating deep high pressure and 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 capital structure;

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

~~availability of capital and the ability to repay indebtedness when due;~~

~~availability and cost of rigs and other materials and operating equipment;~~

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

~~the ability to find, acquire, market, develop and produce new natural gas and oil properties;~~

~~interest rate volatility;~~

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

~~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 find and retain skilled personnel;~~

~~strength and financial resources of competitors;~~

~~federal and state legislative and regulatory developments and approvals;~~

~~worldwide economic conditions;~~

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

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~~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; and~~

~~our ability to obtain insurance coverage on commercially reasonable terms.~~

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. All forward-looking statements 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.

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. 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.

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 ~~2016~~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. 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 those factors summarized below:

our ability to continue as a going concern;

our ability to refinance or extend our Credit Facility before its maturity date of October 1, 2019;

our ability to comply with, or obtain a waiver for non-compliance of, financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness;

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 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;

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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;

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; and

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

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

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 to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States. On June 14, 2019, following approval by our stockholders at the 2019 annual meeting of stockholders, we

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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.

The following table lists our primary producing areas as of ~~September~~June 30, ~~2017:~~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)
~~Pecos County, Texas~~		~~Southern Delaware Basin (Wolfcamp)~~
~~Texas Gulf Coast~~		~~Conventional and unconventional formations~~
Zavala and Dimmit counties, Texas		Buda / ~~Austin Chalk~~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 ~~the three months ended September 30, 2017.~~all periods shown in this report.

In July 2016, we purchased approximately 12,100 gross operated undeveloped acres (5,000 net acres) in the Southern Delaware Basin in Pecos County, Texas (the “Acquisition”), which we began drilling during the fourth quarter of 2016, and increased our acreage to approximately 13,600 gross operated acres (6,800 net) as of September 30, 2017.Capital Expenditures

Our ~~2017~~2019 capital program has focused, and will continue to focus, on the development of our ~~Southern Delaware Basin acreage. Additionally, we will continue to identify opportunities for cost efficiencies~~approximate 17,000 gross operated (8,100 total net) acres in ~~all areas of~~ our operations, maintain core leases and continue to identify new resource potential opportunities internally and, where appropriate, through acquisition. We will continuously monitor the commodity price environment, including its stability and forecast, and, if warranted, make adjustments to our strategy as the year progresses.

~~Capital Expenditures~~

~~Our~~ Southern Delaware Basin acreage ~~has generated,~~in Pecos County, Texas. Due to limited liquidity and ~~is expected~~near-term expiration of our credit facility (as discussed below), while we review liquidity-enhancing alternative sources of capital, we intend to continue to ~~generate, positive returns on~~minimize our drilling ~~investment, even~~program capital expenditures in the ~~current commodity price environment. Assuming we achieve our expected results and market conditions do not deteriorate, we will continue to drill throughout the year. Until~~Southern Delaware Basin. In addition, until a sustained improvement in commodity prices occurs, ~~however,~~ we ~~do not currently expect to devote meaningful~~will commit drilling capital to ~~the development of our~~West Texas, and other areas, ~~and will devote capital~~only to ~~those areas to~~ fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand our presence in those existing areas. Despite challenges experienced throughout the Southern Delaware Basin related to constrained production takeaway capacity, and the adverse impact on commodity price differentials, we still generate positive returns to date on our drilling investment. We continuously monitor the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, will make adjustments to our capital program as the year progresses. We will continue to make balance sheet strength a priority in ~~2017,~~2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales.

Additionally, we will continue to ~~evaluate new organic~~identify opportunities for ~~growth~~cost reductions and operating efficiencies in all areas of our operations, while also searching for new resource acquisition opportunities. Acquisition efforts will ~~continue~~be focused on areas in which we can leverage our geological and operational experience and expertise to ~~evaluate pursuing stressed or distressed acquisition~~exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that ~~may arise in this low commodity price environment. We retain the flexibility~~we believe will enable us to ~~be more aggressive in our drilling plans should actual results exceed expectations and/or commodity prices improve, thereby making increased drilling an appropriate business decision.~~economically grow production and add reserves.

Southern Delaware Basin (West Texas)

~~Since the closing of the Acquisition, we and our partner have increased our leasehold footprint to approximately 13,600 gross operated acres, or approximately 6,800 net acres to Contango.~~ As of ~~September 30, 2017,~~December 31, 2018, we ~~currently estimate that~~had nine wells producing from the Wolfcamp A formation, three wells producing from the Wolfcamp B formation, and a fourth Wolfcamp B well, the Ripper State #2H, which was drilled in November 2018. The Ripper State #2H was recently completed and initiated flow back in late July 2019.

On April 24, 2019, we ~~have close to 200 gross drilling locations in~~spud the ~~Southern Delaware Basin, initially~~American Hornet #1H, targeting the Wolfcamp A formation. This well was drilled to a total measured depth of approximately 20,100 feet, including an approximate 9,800 foot lateral. Completion operations began in late July 2019, and production is expected to begin later in the third quarter.

On March 19, 2019, we spud the Iron Snake #1H, targeting the Wolfcamp B ~~and Second Bone Spring formations. Substantially all~~formation. This well was drilled to a total measured depth of ~~these locations can accommodate 10,000~~approximately 20,500 feet, including an approximate 10,100 foot ~~laterals. In January 2017, we initiated flowback on our first well~~lateral. Completion operations are expected to begin in September 2019, with production expected to begin in the ~~Southern Delaware Basin,~~fourth quarter.

On June 3, 2019, we spud the Breakthrough State #1H, targeting the Wolfcamp A formation. This well was drilled to a total measured depth of approximately 20,300 feet, including an approximate 9,800 foot lateral. Completion operations are expected to begin later this fall, with production expected to begin in the fourth quarter.

2325

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Lonestar-Gunfighter #1H, an Upper Wolfcamp A test well in the northwest portion of our acreage position, on a controlled flow basis, reaching a maximum 24-hour initial production (“IP”) rate of 966 Boed (72% oil).

Our next two wells, the Rude Ram #1H and the Ripper State #1H, were drilled from a common surface location one mile south of the Lonestar-Gunfighter #1H, each well also targeting the Upper Wolfcamp A. Both wells initiated flow back in May 2017. The Rude Ram #1H reached a maximum 24-hour IP rate of 1,304 Boed (69% oil), while the Ripper State #1H reached a maximum 24-hour IP rate of 1,131 Boed (73% oil). In February 2017, we spud a pilot test well, the Grim Reaper #1H, approximately 1.5 miles to the southeast of the Rude Ram and Ripper State. The Grim Reaper was initially drilled as a pilot well through the Lower Wolfcamp, and after experiencing casing problems in the intermediate hole section, logs were run, and the well was completed vertically with multistage fracs in the Lower Wolfcamp to evaluate future potential.

Our fourth horizontal well in the area, the Gunner #2H, was spud in April 2017, targeting the Lower Wolfcamp A. The Gunner #2H is approximately two miles to the northeast of the Grim Reaper #1H and initiated flow back in early August 2017, reaching a maximum 24-hour IP rate of 1,348 Boed (77% oil). In June 2017,On July 4, 2019, we spud the ~~Fighting Ace~~Old Ironside #1H, ~~which encountered mechanical difficulties and was temporarily abandoned. We expect this well bore could have future utility for a possible shallower Bone Springs test.~~

Our fifth horizontal well, the Crusader #1H, was spud in June 2017, targeting the Lower Wolfcamp A. Completion operations with 50 stages of fracture stimulation are expected to commence in early January 2018. Our sixth horizontal well, the Ragin Bull #1H was spud in September 2017 targeting the Wolfcamp ~~formation~~A formation. This well was drilled to ~~satisfy lease considerations~~a total measured depth of approximately 20,400 feet, including an approximate 9,900 foot lateral, with completion operations expected to begin later this fall and ~~we are currently~~production expected to begin in the ~~lateral section.~~fourth quarter.

Impairment of Long-Lived Assets

We recognized nonon-cash proved property impairment of ~~proved properties~~$0.2 million for the six months ended June 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 ~~three and nine months~~quarter ended ~~September 30, 2017.~~December 31, 2018. 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 nonon-cash impairment expense of approximately $0.9 million for the six months ended June 30, 2019, related to impairment of certain unproved properties ~~for~~primarily due to expiring leases.

Going Concern Assessment

As discussed below under “Capital Resources and Liquidity”, our Credit Facility (as defined in “Capital Resources and Liquidity”) currently matures on October 1, 2019. Over the ~~three~~past several months, ~~ended September 30, 2017~~we have been in discussions with our current lenders and ~~$1.4 million~~other sources of capital regarding a possible refinancing and/or replacement of our existing Credit Facility. There is no assurance, however, that such discussions will result in ~~impairment expense related~~a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. These conditions raise substantial doubt about our ability to continue as a going concern. However, the ~~partial impairment~~accompanying financial statements have been prepared assuming we will continue to operate as a going concern, which contemplates the realization of ~~two unused offshore platforms for~~assets and the ~~nine months ended September 30, 2017.~~satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should we be unable to continue as a going concern.

Summary Production Information

Our production for the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~69%~~59% offshore and ~~31%~~41% onshore, volumetrically, and was comprised of ~~68%~~55% natural gas, ~~16%~~26% oil and ~~16%~~19% natural gas liquids. Our production for the three months ended ~~September~~June 30, ~~2016~~2018 was ~~67%~~56% offshore and ~~33%~~44% onshore, volumetrically, and was comprised of approximately ~~71%~~59% natural gas, ~~12%~~24% oil and 17% natural gas liquids.

~~Table of Contents~~

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, 2016

December 31, 2016

March 31, 2017

June 30, 2017

September 30, 2017

Offshore GOM

Dutch and Mary Rose (1)

39.3

39.5

35.4

36.3

32.2

Vermilion 170 (2)

4.0

4.9

4.6

3.1

4.2

South Timbalier 17 (3)

0.6

0.6

0.5

0.2

0.1

Southeast Texas (4)

12.1

10.1

8.6

8.2

7.8

South Texas (5)

7.5

7.5

6.4

5.6

4.6

Other (6)

2.2

1.7

2.1

4.6

4.3

65.7

64.3

57.6

58.0

53.2


	Three Months Ended
	June 30, 2018	September 30, 2018	December 31, 2018	March 31, 2019	June 30, 2019
Offshore (1)	23.7	27.2	25.3	23.5	19.1
West Texas	6.7	6.4	7.5	5.9	5.9
Other Onshore (2)	12.0	10.0	7.0	6.5	7.3
	42.4	43.6	39.8	35.9	32.3

(1)

~~Includes 26 day shut in for compressor repair~~Our Vermilion 170 well was sold effective December 1, 2018 and produced at an average daily rate of 2.2 Mmcfe/d during ~~the~~2018. The three months ended ~~March 31, 2017.~~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 ~~a decreased~~Woodbine production ~~rate of 0.8 Mmcfe/d due to temporary pipeline limitations~~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 ~~June 30, 2017.~~

~~(3)~~

~~South Timbalier 17 ceased production~~December 31, 2018 is primarily due to the Liberty and Hardin County property sale in ~~August 2017.~~

~~(4)~~

~~Includes Madison and Grimes counties, among others.~~

~~(5)~~

~~Includes Zavala and Dimmit counties, among others.~~

~~(6)~~

~~Includes onshore wells primarily in Colorado, East Texas, and Wyoming during 2016 and onshore wells primarily in East Texas, Wyoming and West Texas during 2017.~~November 2018.

Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, ~~(“Contaro”) currently has~~owns a 37% ownership interest in Exaro. As of ~~September~~June 30, ~~2017,~~2019, Exaro had ~~646~~648 wells on production over its 5,760 gross acres (1,040 net), with a working interest between 2.4% and 32.5%.

Table of Contents

These wells were producing at a rate of approximately ~~27 Mmcfed,~~19 Mmcfe/d, net to Exaro. ~~The operator of these interests has applied for multiple drilling permits for horizontal wells that will be located on parts~~As a result of our ~~acreage. Exaro’s working interest~~investment in ~~the drilling spacing units for the applied for horizontal wells ranges from 1% to 6%. As of September 30, 2017, the operator has been approved to drill two horizontal wells, in which~~ Exaro, ~~has a net working interest of 2.4%. For the three months ended September 30, 2017 and 2016,~~ we recognized an investment gain of approximately $0.4 million, net of no tax expense, and an investment loss of approximately $0.5 million, net of no tax expense, ~~as a result of our investment in Exaro. For~~for the ~~nine~~three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016, we~~2018, respectively. We recognized an investment gain of approximately ~~$2.5~~$0.7 million, net of no tax expense, and aan investment gain of approximately ~~$1.8~~$0.2 million, net of no tax expense, for the six months ended June 30, 2019 and 2018, respectively. See Note 89 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.

~~Other~~Non-Core Asset Sales

~~We intend to continue to evaluate potential acquisition opportunities to expand~~As we have expanded our presence in ~~resource plays,~~the Southern Delaware Basin, we also began to ~~exploit~~sell non-core assets to enhance our ~~oil~~liquidity, eliminate marginal assets and ~~liquids-rich positions~~reduce administrative costs by focusing our efforts on West Texas. These asset sales provide some immediate liquidity and ~~to continue to develop exploration~~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 ~~exploitation opportunities where commodity price-justified. Acquisition efforts will typically be focused~~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 ~~areas in which we can leverage our geographic and geological expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling~~two nearby prospects that would produce through this platform. In June 2019, we ~~believe will enable us to grow production~~also sold certain minor, non-core operated assets located in Lavaca and ~~add reserves.~~Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the sold properties.

2527

Table of Contents

Results of Operations for the Three and ~~Nine months~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~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~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~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 ~~lease~~ operating expenses include production taxes, such as ad valorem and severance taxes.

Three Months Ended September 30,

Nine Months Ended September 30,


2017

2016

%

2017

2016

%

Revenues (thousands):

Oil and condensate sales

$
6,109

$
4,946

24
%

$
18,134

$
17,164

6
%
Natural gas sales

9,681

12,011

(19)
%

31,956

31,283

2
%
NGL sales

3,040

2,619

16
%

8,440

8,073

5
%
Total revenues

$
18,830

$
19,576

(4)
%

$
58,530

$
56,520

4
%

Production:

Oil and condensate (thousand barrels)

Offshore GOM

23

19

21
%

78

106

(26)
%
Southeast Texas

35

54

(35)
%

117

190

(38)
%
South Texas

19

28

(32)
%

68

95

(28)
%
Other

55

18

206
%

125

79

58
%
Total oil and condensate

132

119

11
%

388

470

(17)
%
Natural gas (million cubic feet)

Offshore GOM

2,702

3,327

(19)
%

8,618

10,841

(21)
%
Southeast Texas

324

469

(31)
%

999

1,666

(40)
%
South Texas

232

407

(43)
%

837

1,137

(26)
%
Other

57

92

(38)
%

196

245

(20)
%
Total natural gas

3,315

4,295

(23)
%

10,650

13,889

(23)
%
Natural gas liquids (thousand barrels)

Offshore GOM

87

99

(12)
%

254

323

(21)
%
Southeast Texas

31

53

(42)
%

89

176

(49)
%
South Texas

13

19

(32)
%

43

55

(22)
%
Other

1

2

(50)
%

11

6

83
%
Total natural gas liquids

132

173

(24)
%

397

560

(29)
%
Total (million cubic feet equivalent)

Offshore GOM

3,360

4,035

(17)
%

10,608

13,415

(21)
%
Southeast Texas

721

1,113

(35)
%

2,239

3,866

(42)
%
South Texas

424

689

(38)
%

1,507

2,035

(26)
%
Other

396

210

89
%

1,005

750

34
%
Total production

4,901

6,047

(19)
%

15,359

20,066

(23)
%

Daily Production:

Oil and condensate (thousand barrels per day)

Offshore GOM

0.2

0.2

21
%

0.3

0.4

(26)
%
Southeast Texas

0.4

0.6

(35)
%

0.4

0.7

(38)
%
South Texas

0.2

0.3

(32)
%

0.3

0.3

(28)
%
Other

0.6

0.2

206
%

0.4

0.3

58
%
Total oil and condensate

1.4

1.3

11
%

1.4

1.7

(17)
%
Natural gas (million cubic feet per day)

Offshore GOM

29.4

36.2

(19)
%

31.6

39.5

(21)
%
Southeast Texas

3.5

5.1

(31)
%

3.7

6.1

(40)
%
South Texas

2.5

4.4

(43)
%

3.1

4.1

(26)
%
Other

0.6

1.0

(38)
%

0.6

0.9

(20)
%
Total natural gas

36.0

46.7

(23)
%

39.0

50.6

(23)
%


	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		%		2019		2018		%

Revenues (thousands):
Oil and condensate sales	$	7,439	$	9,607	(23)	%	$	13,845	$	18,418	(25)	%
Natural gas sales		3,857		5,848	(34)	%		9,499		14,457	(34)	%
NGL sales		1,466		2,993	(51)	%		3,429		6,010	(43)	%
Total revenues	$	12,762	$	18,448	(31)	%	$	26,773	$	38,885	(31)	%

Production:
Oil and condensate (thousand barrels)
Offshore GOM		10		18	(44)	%		23		37	(38)	%
West Texas		60		70	(14)	%		125		122	2	%
Other Onshore		57		63	(10)	%		105		133	(21)	%
Total oil and condensate		127		151	(16)	%		253		292	(13)	%
Natural gas (million cubic feet)
Offshore GOM		1,325		1,695	(22)	%		2,960		3,991	(26)	%
West Texas		88		80	10	%		152		126	21	%
Other Onshore		215		504	(57)	%		409		1,075	(62)	%
Total natural gas		1,628		2,279	(29)	%		3,521		5,192	(32)	%
Natural gas liquids (thousand barrels)
Offshore GOM		58		59	(2)	%		124		137	(9)	%
West Texas		15		18	(17)	%		29		25	16	%
Other		19		34	(44)	%		37		74	(50)	%
Total natural gas liquids		92		111	(17)	%		190		236	(19)	%
Total (million cubic feet equivalent)
Offshore GOM		1,736		2,156	(19)	%		3,847		5,033	(24)	%
West Texas		541		606	(11)	%		1,075		1,008	7	%
Other Onshore		665		1,092	(39)	%		1,255		2,317	(46)	%
Total production		2,942		3,854	(24)	%		6,177		8,358	(26)	%

Daily Production:
Oil and condensate (thousand barrels per day)
Offshore GOM		0.1		0.2	(44)	%		0.1		0.2	(38)	%
West Texas		0.7		0.8	(14)	%		0.7		0.7	2	%
Other Onshore		0.6		0.7	(10)	%		0.6		0.7	(21)	%
Total oil and condensate		1.4		1.7	(16)	%		1.4		1.6	(13)	%
Natural gas (million cubic feet per day)
Offshore GOM		14.6		18.6	(22)	%		16.4		22.1	(26)	%
West Texas		1.0		0.9	10	%		0.8		0.7	21	%
Other Onshore		2.3		5.5	(57)	%		2.3		5.9	(62)	%
Total natural gas		17.9		25.0	(29)	%		19.5		28.7	(32)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM		0.6		0.6	(2)	%		0.7		0.8	(9)	%
West Texas		0.2		0.2	(17)	%		0.2		0.1	16	%
Other		0.2		0.4	(44)	%		0.1		0.4	(50)	%
Total natural gas liquids		1.0		1.2	(17)	%		1.0		1.3	(19)	%

2628

Table of Contents


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017		2016		%		2017		2016		%		2019		2018		%		2019		2018		%

Natural gas liquids (thousand barrels per day)
Offshore GOM		0.9		1.1	(12)	%		1.0		1.2	(21)	%
Southeast Texas		0.3		0.6	(42)	%		0.3		0.6	(49)	%
South Texas		0.1		0.2	(32)	%		0.2		0.2	(22)	%
Other		0.1		—	(50)	%		—		—	83	%
Total natural gas liquids		1.4		1.9	(24)	%		1.5		2.0	(29)	%
Total (million cubic feet equivalent per day)
Offshore GOM		36.5		43.9	(17)	%		38.9		48.9	(21)	%		19.1		23.7	(19)	%		21.3		27.8	(24)	%
Southeast Texas		7.8		12.1	(35)	%		8.2		14.1	(42)	%
South Texas		4.6		7.5	(38)	%		5.5		7.4	(26)	%
Other		4.3		2.2	89	%		3.7		2.8	34	%
West Texas														5.9		6.7	(11)	%		5.9		5.6	7	%
Other Onshore														7.3		12.0	(39)	%		6.9		12.8	(46)	%
Total production		53.2		65.7	(19)	%		56.3		73.2	(23)	%		32.3		42.4	(24)	%		34.1		46.2	(26)	%

Average Sales Price:
Oil and condensate (per barrel)	$	46.30	$	41.63	11	%	$	46.76	$	36.49	28	%	$	58.42	$	63.53	(8)	%	$	54.78	$	63.16	(13)	%
Natural gas (per thousand cubic feet)	$	2.92	$	2.80	4	%	$	3.00	$	2.25	33	%	$	2.37	$	2.57	(8)	%	$	2.70	$	2.78	(3)	%
Natural gas liquids (per barrel)	$	22.98	$	15.10	52	%	$	21.26	$	14.40	48	%	$	16.01	$	26.84	(40)	%	$	18.05	$	25.32	(29)	%
Total (per thousand cubic feet equivalent)	$	3.84	$	3.24	19	%	$	3.81	$	2.82	35	%	$	4.34	$	4.79	(9)	%	$	4.33	$	4.65	(7)	%

Expenses (thousands):
Operating expenses	$	7,041	$	8,158	(14)	%	$	20,203	$	22,782	(11)	%	$	5,694	$	6,478	(12)	%	$	10,886	$	13,405	(19)	%
Exploration expenses	$	315	$	444	(29)	%	$	690	$	1,088	(37)	%	$	249	$	394	(37)	%	$	473	$	863	(45)	%
Depreciation, depletion and amortization	$	11,193	$	15,166	(26)	%	$	35,678	$	49,586	(28)	%	$	7,573	$	9,498	(20)	%	$	15,129	$	19,983	(24)	%
Impairment and abandonment of oil and gas properties	$	84	$	1,165	(93)	%	$	1,515	$	4,268	(65)	%	$	1,247	$	777	60	%	$	1,834	$	4,104	(55)	%
General and administrative expenses	$	6,219	$	7,486	(17)	%	$	18,648	$	18,772	(1)	%	$	4,456	$	5,354	(17)	%	$	9,461	$	12,080	(22)	%
Gain from investment in affiliates (net of taxes)	$	525	$	467	12	%	$	2,475	$	1,802	37	%
Gain (loss) from investment in affiliates (net of taxes)													$	427	$	(475)	(190)	%	$	457	$	232	97	%

Selected data per Mcfe:
Operating expenses	$	1.44	$	1.35	7	%	$	1.32	$	1.14	16	%	$	1.94	$	1.68	15	%	$	1.76	$	1.60	10	%
General and administrative expenses	$	1.27	$	1.24	2	%	$	1.21	$	0.94	29	%	$	1.51	$	1.39	9	%	$	1.53	$	1.45	6	%
Depreciation, depletion and amortization	$	2.28	$	2.51	(9)	%	$	2.32	$	2.47	(6)	%	$	2.57	$	2.46	4	%	$	2.45	$	2.39	3	%

Three Months Ended ~~September~~June 30, ~~2017~~2019 Compared to Three Months Ended ~~September~~June 30, ~~2016~~2018

Natural Gas, Oil and NGL Sales and Production

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

We reported revenues of ~~$18.8~~$12.8 million for the three months ended ~~September~~June 30, ~~2017,~~2019, compared to revenues of ~~$19.6~~$18.4 million for the three months ended ~~September~~June 30, ~~2016.~~2018. The decrease in revenues was primarily attributable to lower natural gas production, ~~and~~which was mostly related to non-core property sales ~~which~~and offshore downtime for pipeline and compressor repair and maintenance, as well as the expected year over year decline in our offshore properties. The decrease in revenues was ~~partially offset by higher commodity prices.~~also due to lower oil production related to the temporary suspension of our drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 because of the unstable oil price environment,

Total equivalent production was ~~53.2 Mmcfed~~32.3 Mmcfe/d for the three months ended ~~September~~June 30, ~~2017,~~2019, compared to ~~65.7 Mmcfed~~42.4 Mmcfe/d in the prior year quarter. ~~The decrease~~Net natural gas production for the three months ended June 30, 2019 was ~~attributable~~approximately 17.9 Mmcf/d, compared with approximately 25.0 Mmcf/d for the three months ended June 30, 2018, with approximately 80% of the decline related to ~~a 12.9 Mmcfed decrease in production resulting from~~non-core property sales, and the remainder primarily due to downtime associated with offshore pipeline and compressor repair and maintenance and normal field decline ~~and limited 2016 drilling, a 1.6 Mmcfed decline~~in our offshore properties. NGL production decreased from ~~downtime associated with the impact of Hurricane Harvey, and a 1.2 Mmcfed decline from~~approximately 1,200 barrels per day to 1,000 barrels per day, mostly related to non-core property ~~sales, offset~~sales. Net oil production decreased from approximately 1,700 barrels per day to 1,400 barrels per day primarily due to the temporary suspension of our drilling program in ~~part by 3.2 Mmcfed~~West Texas for the fourth quarter of ~~new~~2018 and first quarter of 2019. The higher-unit value oil and NGL production (but lower volume equivalency than gas) increased from ~~drilling~~41% to 45% of total production due to our focus on our ~~Southern Delaware Basin acreage.~~

oil-weighted West Texas drilling program. West Texas accounted for 18% of total equivalent production for the three months ended June 30, 2019, as compared to 16% of total equivalent production for the three months ended June 30, 2018.

2729

Table of Contents

Average Sales Prices

The average equivalent sales price realized for the three months ended ~~September~~June 30, ~~2017~~2019 was ~~$3.84~~$4.34 per Mcfe compared to ~~$3.24~~$4.79 per Mcfe for the three months ended ~~September~~June 30, ~~2016.~~2018. This ~~increase~~decrease was attributable primarily to the ~~increase~~decrease in the realized price of oil to ~~$46.30~~$58.42 per barrel ~~compared to $41.63~~from $63.53 per barrel for the three months ended ~~September~~June 30, ~~2016,~~2018, and to the ~~increase~~decrease in the realized price of ~~natural gas liquids~~NGLs to ~~$22.98~~$16.01 per barrel, ~~compared to $15.10~~from $26.84 per barrel for the three months ended ~~September~~June 30, ~~2016.~~2018.

Operating Expenses

Operating expenses for the three months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$7.0~~$5.7 million, or ~~$1.44~~$1.94 per Mcfe, compared to ~~$8.2~~$6.5 million, or ~~$1.35~~$1.68 per Mcfe, for the three months ended ~~September~~June 30, ~~2016.~~2018. The table below provides additional detail of operating expenses for each of the three month periods:


	Three Months Ended September 30,						Three Months Ended June 30,
	2017			2016			2019			2018
	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)
Lease operating expenses	$	4,585	0.94	$	4,580	$ 0.76	$	3,629	$ 1.23	$	4,852	$ 1.26
Production & ad valorem taxes		625	0.13		755	0.12		657	0.22		836	0.22
Transportation & processing costs		868	0.18		2,188	0.36		502	0.17		285	0.07
Workover costs		963	0.19		635	0.11		906	0.32		505	0.13
Total operating expenses	$	7,041	1.44	$	8,158	$ 1.35	$	5,694	1.94	$	6,478	$ 1.68

Lease operating expenses decreased from $4.9 million during the three months ended June 30, 2018 to $3.6 million for the three months ended June 30, 2019, primarily due to our non-core property sales.

Production and ad valorem ~~taxes~~expenses decreased ~~by 17%~~from $0.8 million during the three months ended June 30, 2018 to $0.7 million for the three months ended ~~September~~June 30, ~~2017, compared to the three months ended September 30, 2016,~~2019, primarily as a result of lower production associated with our non-core property ~~sales and lower legacy production, partially offset by production taxes on new West Texas production.~~sales.

Transportation &and processing costs ~~decreased by 60%~~increased from $0.3 million during the three months ended June 30, 2018 to $0.5 million for the three months ended ~~September~~June 30, ~~2017, compared~~2019, primarily due to a prior period adjustment related to an offshore processing fee overcharge, which caused 2018 costs to be lower than usual.

Impairment and Abandonment Expenses

During the three months ended ~~September~~June 30, ~~2016,~~2019, we 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 a higher minimum volume charge in 2016 for an ongoing throughput deficiency in our Madisonville Field. See Note 12 to our Financial Statements - “Commitments and Contingencies” for additional details related to this fee.

~~Impairment Expenses~~

~~No impairment expense was recorded for~~revised reserve estimates made during the quarter ended December 31, 2018. During the three months ended ~~September~~June 30, ~~2017. Impairment~~2018, we recognized $0.4 million in non-cash proved property impairment due to revised reserve estimates. We recognized non-cash unproved impairment expense ~~for~~of approximately $0.4 million, primarily related to expiring leases, during each of the three months ended ~~September~~June 30, ~~2016 included a $1.1~~2019 and June 30, 2018. We recognized abandonment expense of approximately $0.6 million ~~impairment and partial impairment~~during the three months ended June 30, 2019. An immaterial amount of ~~certain unproved properties and onshore prospects due primarily to~~abandonment expense was recognized during the sustained low commodity price environment and expiring leases, substantially all of which was related to unproved lease cost amortization of marginal, non-core properties in Fayette and Gonzales counties, Texas.three months ended June 30, 2018.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~$11.2~~$7.6 million, or ~~$2.28~~$2.57 per Mcfe. This compares to approximately ~~$15.2~~$9.5 million, or ~~$2.51~~$2.46 per Mcfe, for the three months ended ~~September~~June 30, ~~2016.~~2018. The lower depletion expense for the three months ended ~~September~~June 30, ~~2017~~2019 was ~~primarily~~ attributable to lower production.

General and Administrative Expenses

~~General~~Total general and administrative expenses for the three months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$6.2~~$4.5 million, compared to ~~$7.5~~$5.4 million for the three months ended ~~September~~June 30, 2016. These expenses are primarily related to cash compensation and benefits, stock based compensation, professional fees and office costs. General and administrative expenses for the three months ended September 30, 2016 were higher primarily due to payout of the Company’s salary replacement program, which temporarily deferred 10% of 2015 employee salaries and director fees, and an adjustment to the 2016 bonus accrual due to the improvement in performance compared to goals. General and administrative expenses also included approximately $1.5 million and $1.3 million in non-cash stock based compensation, for the current and prior year quarters, respectively.2018.

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


	Three Months Ended June 30,
	2019		2018
	(in thousands)
Wages and benefits (1)	$	1,206	$	1,719
Non-cash stock-based compensation (1)		584		1,583
Professional fees (2)		1,021		754
Professional fees - special (3)		985		—
Other (4)		660		1,298
Total general and administrative expenses	$	4,456	$	5,354

(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 fees related to insurance, office costs and other company expenses.

Gain (Loss) from Affiliates

For the ~~three months~~quarters ended ~~September~~June 30, ~~2017~~2019 and ~~September~~June 30, ~~2016, the Company~~2018, we recorded a gain from affiliates of approximately $0.4 million, net of no tax expense, and a loss of $0.5 million, net of no tax expense, respectively, related to our investment in Exaro.

~~Nine~~Gain from Sale of Assets

During the three months ended June 30, 2019, we recorded a gain on sale of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2018 and 2019. During the three months ended June 30, 2018 we recorded a gain on sale of assets of $1.4 million related to the sale of our non-operated assets in Starr County, Texas.

Six Months Ended ~~September~~June 30, ~~2017~~2019 Compared to ~~Nine months~~Six Months Ended ~~September~~June 30, ~~2016~~2018

Natural Gas, Oil and NGL Sales and Production

We reported revenues of ~~$58.5~~$26.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, compared to revenues of ~~$56.5~~$38.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018. The ~~increase~~decrease in revenues was primarily attributable to ~~higher commodity prices,~~lower natural gas production, which ~~offset~~was mostly related to non-core property sales, offshore downtime for pipeline and compressor repair and maintenance and the expected year over year decline in ~~production caused by limited drilling~~our offshore properties. The decrease in ~~2016~~revenues was also due to the ~~low~~temporary suspension of our drilling program in West Texas for the fourth quarter of 2018 and ~~uncertain commodity~~first quarter of 2019 because of the unstable oil price ~~environment and non-core property sales.~~environment.

Total equivalent production was ~~56.3 Mmcfed~~34.1 Mmcfe/d for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, compared to ~~73.2 Mmcfed~~46.2 Mmcfe/d in the prior year quarter. Net natural gas production for the ~~nine~~six months ended ~~September~~June 30, ~~2016. The decrease~~2019 was ~~attributable to a 17.4 Mmcfed~~approximately 19.5 Mmcf/d, compared with approximately 28.7 Mmcf/d for the six months ended June 30, 2018, with approximately half of the decline ~~in production from normal field decline and limited 2016 drilling, a 1.1 Mmcfed decline due~~related to non-core property sales, ~~a 0.5 Mmcfed decline from downtime associated with~~and the ~~impact of Hurricane Harvey, and a 0.3 Mmcfed decline~~remainder primarily due to normal field decline in our offshore properties. NGL production decreased from approximately 1,300 barrels per day to 1,000 barrels per day, mostly related to non-core property sales. Net oil production decreased from approximately 1,600 barrels per day to 1,400 barrels per day primarily due to the temporary ~~pipeline limitations at~~suspension of our drilling program in West Texas for the ~~Vermillion 170 field.~~fourth quarter of 2018 and first quarter of 2019. The ~~decrease in~~higher-unit value oil and NGL production ~~was partially offset by 2.4 Mmcfed~~(but lower volume equivalency than gas) increased from 38% to 43% of ~~new~~total production ~~from drilling~~due to our focus on our ~~Southern Delaware Basin acreage.~~oil-weighted West Texas drilling program. West Texas accounted for 17% of total equivalent production for the six months ended June 30, 2019, as compared to 12% of total equivalent production for the six months ended June 30, 2018.

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Average Sales Prices

The average equivalent sales price realized for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$3.81~~$4.33 per Mcfe compared to ~~$2.82~~$4.65 per Mcfe for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018. This ~~increase~~decrease was attributable primarily to the ~~increase~~decrease in the realized price of ~~natural gas~~oil to ~~$3.00~~$54.78 per ~~Mcf, compared to $2.25~~barrel, from $63.16 per ~~Mcf~~barrel for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018, and to the ~~increase~~decrease in the realized price of ~~natural gas liquids~~NGLs to ~~$21.26~~$18.05 per barrel, ~~compared to $14.40~~from $25.32 per barrel for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018.

Operating Expenses

Operating expenses for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$20.2~~$10.9 million, or ~~$1.32~~$1.76 per Mcfe, compared to ~~$22.8~~$13.4 million, or ~~$1.14~~$1.60 per Mcfe, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018. The table below provides additional detail of operating expenses for each of the ~~nine~~six month periods:


	Nine Months Ended September 30,						Six Months Ended June 30,
	2017			2016			2019			2018
		(in thousands)	(per Mcfe)		(in thousands)	(per Mcfe)		(in thousands)	(per Mcfe)		(in thousands)	(per Mcfe)
Lease operating expenses	$	13,428	$ 0.87	$	14,487	$ 0.72	$	7,314	$ 1.17	$	9,896	$ 1.18
Production & ad valorem taxes		1,993	0.13		2,809	0.14		1,043	0.17		1,618	0.19
Transportation & processing costs		2,982	0.19		4,397	0.23		1,197	0.19		882	0.11
Workover costs		1,800	0.13		1,089	0.05		1,332	0.23		1,009	0.12
Total operating expenses	$	20,203	1.32	$	22,782	$ 1.14	$	10,886	1.76	$	13,405	$ 1.60

Lease operating expenses decreased from $9.9 million during the six months ended June 30, 2018 to $7.3 million for the six months ended June 30, 2019, primarily due to our non-core property sales.

Production and ad valorem ~~taxes~~expenses decreased ~~by 29%~~from $1.6 million during the six months ended June 30, 2018 to $1.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to the nine months ended September 30, 2016,~~2019, primarily as a result of lower production associated with our non-core property ~~sales and lower legacy production, partially offset by production taxes on new West Texas production.~~sales.

Transportation &and processing costs ~~decreased by 32%~~increased from $0.9 million during the six months ended June 30, 2018 to $1.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared~~2019, primarily due to the ~~nine months ended September 30, 2016, due~~final accrual in 2019 for our estimated remaining throughput commitment fee in Southeast Texas, and a prior period credit related to ~~a final minimum volume charge on two wells in our South Texas~~

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~~region in 2016, a higher minimum volume charge in 2016 for~~ an ~~ongoing throughput deficiency in our Madisonville Field, and transportation~~offshore processing fee overcharge, which caused 2018 costs ~~on higher 2016 production from our Dutch and Mary Rose Field.~~to be lower than usual. See Note 12 ~~to our Financial Statements -~~– “Commitments and Contingencies” for ~~additional details related to~~further information regarding the ~~Madisonville Field~~throughput commitment fee.

Impairment and Abandonment Expenses

~~Impairment expense~~

During the six months ended June 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to expiring 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, compared to $2.7 million in non-cash impairment charges for the ~~nine~~six months ended ~~September~~June 30, ~~2017 was $1.4 million~~2018, related to revised reserve estimates of onshore and offshore proved properties. During the ~~partial impairment of two unused offshore platforms. Impairment expense for the nine~~six months ended ~~September~~June 30, ~~2016 included a $0.7 million impairment of proved properties. Substantially all of the~~2019 and 2018, we recognized non-cash impairment ~~charge in the prior year period was~~expense of approximately $0.9 million and approximately $1.2 million, respectively, related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Impairment expense for the nine months ended September 30, 2016 also included a $3.4 million impairment and partial impairment of certain non-core unproved properties primarily due to expiring leases. We recognized abandonment expense of approximately $0.7 million and ~~onshore prospects due primarily to~~$0.2 million during the ~~sustained low commodity price environment~~six months ended June 30, 2019 and ~~expiring leases, substantially all of which was related to unproved lease cost amortization of marginal, non-core properties in Fayette and Gonzales counties, Texas.~~June 30, 2018, respectively.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~$35.7~~$15.1 million, or ~~$2.32~~$2.45 per Mcfe. This compares to approximately ~~$49.6~~$20.0 million, or ~~$2.47~~$2.39 per Mcfe, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018. The lower depletion expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~primarily~~ attributable to lower production.

General and Administrative Expenses

~~General~~Total general and administrative expenses for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$18.6~~$9.5 million, compared to ~~$18.8~~$12.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016. General and administrative expenses are primarily related to cash compensation and benefits, stock based compensation, professional fees and office costs. General~~2018.

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The table below provides additional detail of general and administrative expenses for each of the ~~current year included approximately $4.6 million in non-cash stock based compensation, while the prior year included approximately $4.3 million in non-cash stock based compensation.~~six month periods:


	Six Months Ended June 30,
	2019		2018
	(in thousands)
Wages and benefits (1)	$	2,057	$	4,442
Non-cash stock-based compensation (1)		1,637		3,008
Professional fees (2)		2,128		2,040
Professional fees - special (3)		1,736		—
Other (4)		1,903		2,590
Total general and administrative expenses	$	9,461	$	12,080

(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 fees related to insurance, office costs and other company expenses.

Gain from Affiliates

For the ~~nine~~six months ended ~~September~~June 30, ~~2017, the Company~~2019 and June 30, 2018, we recorded a gain from affiliates of approximately ~~$2.5~~$0.7 million, net of no tax expense, ~~related to our investment in Exaro, compared to~~and a gain of ~~$1.8~~$0.2 million, net of no tax expense, ~~for nine~~respectively, related to our investment in Exaro.

Gain from Sale of Assets

During the six months ended ~~September~~June 30, ~~2016.~~2019, we recorded a gain on sale of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2018 and 2019. During the six months ended June 30, 2018, we recorded a gain on sale of assets of $10.8 million, prior to final closing adjustments, related to the sale of our operated Eagle Ford Shale assets located in Karnes County, Texas and the sale of our non-operated assets in Star County, Texas.

Capital Resources and Liquidity

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we incurred expenditures of ~~$37.6~~$14.7 million on capital projects, including ~~$7.4~~$9.0 million for our drilling program in the Southern Delaware Basin and $1.6 million in leasehold acquisition costs and ~~$30.2~~spud fees in the Southern Delaware Basin. We also incurred $1.7 million for the drilling and completion of two non-operated wells targeting the Georgetown formation in our Other Onshore area. The remaining incurred expenditures are primarily related to workovers.

Our capital expenditure forecast for 2019 is approximately $35.1 million, including $29.2 million in the Southern Delaware Basin. AsFor the rest of ~~September 30, 2017,~~2019, we have budgeted for the completion of the four previously drilled West Texas wells. We expect to bring these wells on production during the third and fourth quarters. If we are able to refinance and/or replace our ~~capital expenditure budget for 2017 was approximately $45 million, including $36.4 million to drill and/or complete eight horizontal gross wells (3.7 net),~~Credit Facility, we believe that our internally generated cash flow and proceeds from the sale of non-core assets, combined with availability under a ~~vertical pilot well, a saltwater disposal well and central facilities, all in our Southern Delaware Basin position.~~

Additionally, the Company often reviews acquisitions and prospects presented to us by third parties, and we may decide to invest in one or more of these opportunities. There can be no assurance that wenew credit facility will invest or that any investment we enter into will be successful. These potential investments are not part of our current capital budget and could require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may not be sufficient to meet the liquidity requirements necessary to fund ~~these opportunities.~~our daily operations and planned capital development and to meet our debt service requirements for the next twelve months. If we are not able to refinance and/or replace our Credit Facility, there is substantial doubt about our ability to continue as a going concern. See “Pursuit of Refinancing and Other Liquidity-Enhancing Initiatives”.

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Cash From Operating Activities

Cash flows ~~from~~provided by operating activities ~~provided~~were approximately ~~$26.1~~$14.9 million in cash for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 compared to ~~$23.6~~$13.3 million provided by operating activities for the same period in ~~2016.~~2018. The table below provides additional detail of cash flows from operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016:~~2018:


	Nine Months Ended September 30,				Six Months Ended June 30,
	2017		2016		2019		2018
	(in thousands)				(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	20,733	$	17,438	$	5,902	$	11,902
Changes in operating assets and liabilities		5,372		6,158		8,996		1,361
Net cash provided by operating activities	$	26,105	$	23,596	$	14,898	$	13,263

Cash From Investing Activities

~~Cash~~Net cash flows used in investing activities were $14.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 were approximately $50.8 million,~~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 $8.5 million for the six months ended June 30, 2018. We expended $30.1 million in cash capital ~~expenditures~~costs, primarily related to drilling and/or completing wells in the Southern Delaware Basin and acquiring or extending unproved ~~leases. Cash flows used~~leases during the quarter, partially offset by $21.6 million provided by the sale of our properties in ~~investing activities for the nine months ended September 30, 2016 were approximately $19.8 million all of which was used for capital expenditures related to acquiring acreage~~Karnes County, Texas and ~~unproved leases~~non-operated properties in the Southern Delaware Basin, completing one well in Wyoming, and acquiring or extending unproved leases in other core areas. Amounts presented include cash payments for accrued amounts at the beginning of each period.Starr County, Texas.

Cash From Financing Activities

Cash flows ~~provided by~~used in financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$24.7~~$0.3 million, primarily related to ~~net borrowings under our credit facility with~~shares withheld from employees for the ~~Royal Bank~~payment of ~~Canada and other lenders (the “RBC Credit Facility”).~~taxes due on vested shares of restricted stock issued. Cash flows used in financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018 were approximately ~~$3.8~~$4.7 million, primarily related to ~~the~~net repayment of ~~net~~ borrowings outstanding under our ~~RBC~~ Credit Facility.

~~RBC~~ Credit Facility

~~In October 2013, we entered into a~~Our $500 million secured revolving credit facility with Royal Bank of Canada and other lenders ~~which~~(the “Credit Facility”), currently matures on October 1, 2019. On June 17, 2019, the Company entered into the Seventh Amendment to the Credit Facility (the “Seventh Amendment”). The Seventh Amendment redetermined the borrowing base at $85 million pursuant to the regularly scheduled redetermination process, with a current availability limit of $75 million. As of June 30, 2019, borrowing availability under the Credit Facility was $13.1 million. The Seventh Amendment also set the next borrowing base redetermination to August 1, 2019. The borrowing base ~~is redetermined each November and May. We are currently going through~~under the ~~redetermination process, but do~~Credit Facility effective August 1, 2019 has not ~~expect a material reduction that would affect our liquidity. As of September 30, 2017,~~yet been determined. If the borrowing base is reduced, we would further minimize our drilling program capital expenditures and repay any borrowings required under the ~~RBC~~ Credit Facility, ~~was $125 million.~~which could necessitate seeking additional sources of financing to comply with any repayment requirements under the Credit Facility.

The ~~RBC~~ Credit Facility contains restrictive covenants which, among other things, ~~restrict the declaration or payment of dividends by Contango and~~ require a Current Ratio of greater than or equal to ~~1.0~~1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the ~~RBC Credit Facility Agreement. As of September 30, 2017, we were in compliance with all covenants under the RBC~~ Credit Facility. The ~~RBC~~ Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants including the current ratio covenant, bankruptcy, insolvency or change of control events. As of June 30, 2019, we were in compliance with all but the Current Ratio covenant under the Credit Facility, and we obtained a waiver for such non-compliance effective June 30, 2019.

Pursuit of Refinancing and Other Liquidity-Enhancing Initiatives

Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our existing Credit Facility, which matures on October 1, 2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. These conditions raise substantial doubt about our ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming we will

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continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should we be unable to continue as a going concern.

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

If we are unable to refinance the Credit Facility in full before the maturity date, we may pursue restructuring initiatives and the lenders may take action that would have a material adverse effect on us. Please read “We may not be able to refinance or replace our maturing debt on favorable terms, or at all, which will materially adversely affect our financial condition and our ability to develop our oil and gas assets.” and “If we are unable to comply with restrictions and covenants in our Credit Facility, there could be a default under the terms of the agreement, which could result in an acceleration of payments of funds that we have borrowed.” in Part I, Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2018.

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our ~~2016~~2018 Form 10-K.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to our Financial Statements – “Summary of

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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~~June 30, ~~2017, the primary off-balance sheet arrangements that~~2019, we have entered into are operating lease agreements, which are customary in the oil and gas industry. Other than the off-balance sheet arrangements shown under operating leases in the commitments and contingencies table included in our 2016 Form 10-K, we have no ~~other~~ 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

~~Commodity Price Risk~~

We are exposed to various risks including energy commodity price risk for our natural gas and oil production. When oil, natural gas and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. Our major commodity price risk exposure is to the prices received for our oil, natural gas and natural gas liquids production. Realized commodity prices received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for oil, natural gas and natural gas liquids are volatile and unpredictable. For the three and nine months ended September 30, 2017,As a ~~10% fluctuation in the prices received for natural gas and oil production would have had an approximate $1.9 million and $5.9 million impact on our revenues, respectively.~~

~~Derivative Instruments and Hedging Activity~~

~~We expect energy prices to remain volatile and unpredictable, therefore~~“smaller reporting company”, we have designed a risk management strategy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our cash flows. The types of derivative instruments that we typically utilize include swaps and costless collars. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 50% of forecasted production from proved developed producing reserves (excluding forecasted offshore production during hurricane season), at the time of hedging, for the following twelve to eighteen months. Our hedge strategy and objectives may change significantly as our operational profile changes and/or commodity prices change.

We are exposed to market risk on our open derivative contracts related to potential nonperformance by our counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current derivative contracts are large financial institutions and also lenders or affiliates of lenders in its RBC Credit Facility. We are not required to ~~post collateral, or pay margin calls, under any of these contracts as they are secured under our RBC Credit Facility.~~

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Currently, we do not have any derivative contracts to reduceprovide the exposure to market rate fluctuations. At September 30, 2017, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. The estimated fair values for financial instruments under ASC 825, Financial Instruments (“ASC 825”) 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, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Note 5 to our Financial Statements - "Derivative Instruments" for more details.

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~~Interest Rate Sensitivity~~

We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and US Prime based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

As of September 30, 2017, our total long-term debt was $79.2 million, which bears interest at a floating or market interest rate that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. During the nine months ended September 30, 2017, our effective rates fluctuated between 4.0% and 7.3%, depending on the term of the specific debt drawdowns. At September 30, 2017, we did not have any outstanding interest rate swap agreements. As of September 30, 2017, the weighted average interest rate on our variable rate debt was 4.90% per year. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our RBC Credit Facility would result in an increase of our interest expenseinformation required by ~~$0.6 million for the nine month period.~~this Item.

~~Other Financial Instruments~~

As of September 30, 2017, we had no cash or cash equivalents based on our cash management policy. Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of September 30, 2017, an immediate 10% change in interest rates would result in a $0.4 million change on our near-term financial condition or results of operations.

Item 4. Controls and Procedures

Our management, with the participation of our President and Chief Executive Officer ~~together with~~and our Chief Financial ~~Officer~~ and ~~Chief~~ Accounting Officer, ~~carried out an evaluation of~~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~~June 30, ~~2017.~~2019. Based upon that evaluation, ~~the Company’s management~~our President and Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of ~~September~~June 30, ~~2017,~~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

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management, including our President and Chief Executive Officer and our Chief Financial ~~Officer~~ and ~~Chief~~ 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 ~~nine~~three months ended ~~September~~June 30, ~~2017~~2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

~~There~~Except as set forth below, there have been no material changes from the risk factors disclosed in Item 1A1A. of Part 1 of our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

Our bylaws provide, subject to limited exceptions, that the United States District Court for the Southern District of Texas will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

Our bylaws provide, subject to limited exceptions, that unless we consent to the selection of an alternative forum, the United States District Court for the Southern District of Texas or, if such court lacks jurisdiction, the state district court of Harris County, Texas, shall, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought in the name or right of the Company or on its behalf, (ii) action asserting a claim for breach of a fiduciary duty owed by any director, officer, employee or other agent of the Company to the Company or the Company’s stockholders, (iii) action asserting a claim arising pursuant to any provision of the Texas Business Organizations Code (the “TBOC”), or our certificate of incorporation or bylaws, or (iv) action asserting a claim governed by the internal affairs doctrine.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock shall be deemed to have notice of and consented to the forum provisions in our bylaws. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, other employees or stockholders, which may discourage lawsuits with respect to such claims.

Our bylaws provide certain limitations with respect to business combinations with affiliated stockholders, which may discourage transactions that would otherwise be preferred by a stockholder.

We have elected not to be governed by Texas business combination law, which prohibits a publicly held Texas corporation from engaging in a business combination with an affiliated shareholder for a period of three years after the affiliated shareholder’s share acquisition date, unless the business combination is approved in a prescribed manner. Our bylaws, however, provide that, subject to certain exceptions, we shall not engage in any business combination (as defined in our bylaws) with any “affiliated stockholder” for a period of three years following the time that such stockholder became an affiliated stockholder, unless:

prior to such time, our board of directors approved either the business combination or the transaction which resulted in the stockholder becoming an affiliated stockholder;

upon consummation of the transaction which resulted in the stockholder becoming an affiliated stockholder, the affiliated stockholder owned at least 85% of our voting common stock outstanding, excluding shares held by certain directors who are also officers;

at or subsequent to such time, the business combination is approved by the affirmative vote of (i) our board of directors and (ii) the holders of at least two-thirds (2/3) of our outstanding voting common stock not owned by the affiliated stockholder or an affiliate or associate of the affiliated stockholder, at a meeting of

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stockholders called for that purpose not less than six months after the transaction which resulted in the stockholder becoming an affiliated stockholder; or

at or subsequent to such time, the business combination is approved by (i) a majority of the directors of our board who are not the affiliated stockholder (or an affiliate or associate thereof, or nominated for election by such affiliated stockholder) and were a member of our board on or prior to June 14, 2019 or were elected or nominated for election by a majority of directors who were members of our board on or prior to June 14, 2019, and (ii) a majority of our voting common stock outstanding.

For purposes of this provision, “affiliated stockholder” means any person that is the owner of 20% or more of the voting common stock outstanding or, during the preceding three-year period, was the owner of 20% or more of our voting common stock outstanding; provided, however, that “affiliated stockholder” does not include certain stockholders whose aggregate ownership does not exceed 23% of our voting common stock outstanding, subject to adjustment by our board of directors. This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. This provision may also have the effect of limiting financing transactions with interested stockholders that could be deemed favorable sources of capital. With the approval of 2/3 of our board of directors or our stockholders, this provision of our bylaws could be amended to further provide antitakeover protection. In addition, with approval of our board of directors and a majority of stockholders, we could change our state of incorporation and modify the antitakeover provisions applicable to us, or we could amend our certificate of incorporation in the future to elect to be governed by the Texas business combination law.

Certain antitakeover provisions may affect your rights as a shareholder.

Our articles of incorporation authorize our board of directors to set the terms of and issue preferred stock without shareholder approval. Our board of directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our revolving credit facility and our indentures governing our senior notes and our outstanding preferred stock contain terms that may restrict our ability to enter into change of control transactions, including requirements to repay borrowings under our revolving credit facility, to offer to repurchase senior notes and to offer to redeem our preferred stock in either event upon a change of control, as determined under the relevant documents relating to such obligations. These provisions, along with specified provisions of the TBOC and our articles of incorporation and bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock.

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

~~None.~~The Company withheld the following shares from employees during the three months ended June 30, 2019 for the payment of taxes due on shares of restricted stock that vested and were issued under its stock-based compensation plans:



				Total Number of Shares		Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part of		of Shares that May Yet
Period	Shares Withheld	Per Share		Publicly Announced Program		be Purchased Under Program

April 2019	14,862	$	3.12	—	$	—
May 2019	1,271	$	2.94	—	$	—
June 2019	—	$	—	—	$	—
Total	16,133	$	3.11	—	$	31.8 million (1)

(1)

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

Item 3. Defaults upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. ~~Exhibits~~Exhibits

Exhibit Number		Description
2.1		Agreement and Plan of Merger dated as of April 26, 2019, by and between Contango Oil & Gas Company and MCF Merger Sub Corp (filed as Exhibit 2.1 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).
3.1		Amended and Restated Certificate of ~~Incorporation~~Formation of Contango Oil & Gas Company (filed as Exhibit ~~3.1~~3.3 to the Company’s ~~Current~~ Report on Form 8-K dated ~~December 1, 2000,~~June 14, 2019, as filed with the Securities and Exchange Commission on ~~December 15, 2000,~~June 14, 2019 and incorporated by reference herein).
3.2		~~Amendment to the Certificate of Incorporation~~Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s ~~Quarterly~~ Report on Form ~~10-QSB for the quarter ended September 30, 2002,~~8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on ~~November~~June 14, ~~2002,~~2019 and incorporated by reference herein).
~~3.3~~10.1		~~Third Amended~~Separation Agreement and ~~Restated Bylaws of~~General Release by Contango Oil & Gas Company and Tommy H. Atkins dated April 16, 2019 (filed as Exhibit ~~3.2~~10.1 to the Company’s ~~Annual~~Current Report on Form ~~10-K for the year ended December 31, 2014,~~8-K dated April 16, 2019, as filed with the Securities and Exchange Commission on ~~March 3, 2015,~~April 17, 2019 and incorporated by reference herein).
10.2		Seventh Amendment to Credit Agreement dated as of June 17, 2019 among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as Administrative Agent, and the Lenders Signatory hereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 17, 2019, as filed with the Securities and Exchange Commission on June 18, 2019 and incorporated by reference herein).
31.1		Certification of Chief Executive Officer required by Rules ~~13a-14~~13a-14(a) and ~~15d-14~~15d-14(a) under the Securities Exchange Act of 1934. †
31.2		Certification of Chief Financial Officer required by Rules ~~13a-14~~13a-14(a) and ~~15d-14~~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.

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SIGNATURES

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


		CONTANGO OIL & GAS COMPANY


Date: ~~November~~August 8, ~~2017~~2019	By:	/S~~/ ALLAN D. KEEL~~ /s/ WILKIE S. COLYER
		~~Allan D. Keel~~Wilkie S. Colyer
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: ~~November~~August 8, ~~2017~~2019	By:	/S/ /s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)


~~Date: November 8, 2017~~	~~By:~~	/S~~/ DENISE DUBARD~~
		~~Denise DuBard~~
		~~Chief Accounting Officer and Controller~~
		~~(Principal Accounting Officer)~~

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	September 30, 2017		December 31, 2016
Current assets (1)	$	15,897	$	25,296
Non-current assets:
Net property and equipment		84,766		90,621
Gas processing deposit		1,150		1,150
Other non-current assets		57		8
Total non-current assets		85,973		91,779
Total assets	$	101,870	$	117,075

Current liabilities (2)	$	3,950	$	65,694
Non-current liabilities:
Long-term debt		44,356		—
Other non-current liabilities		3,466		8,106
Total non-current liabilities		47,822		8,106
Members' equity		50,098		43,275
Total liabilities & members' equity	$	101,870	$	117,075


	Three Months Ended
	September 30, 2016	December 31, 2016	March 31, 2017	June 30, 2017	September 30, 2017
Offshore GOM
Dutch and Mary Rose (1)	39.3	39.5	35.4	36.3	32.2
Vermilion 170 (2)	4.0	4.9	4.6	3.1	4.2
South Timbalier 17 (3)	0.6	0.6	0.5	0.2	0.1
Southeast Texas (4)	12.1	10.1	8.6	8.2	7.8
South Texas (5)	7.5	7.5	6.4	5.6	4.6
Other (6)	2.2	1.7	2.1	4.6	4.3
	65.7	64.3	57.6	58.0	53.2