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 ~~June 30, 2018~~March 31, 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		95-4079863

(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

717 TEXAS AVENUE, SUITE 2900 HOUSTON, TEXAS		77002
(Address of principal executive offices)		(Zip Code)

(713) 236-7400

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically ~~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 ☒

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

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

The total number of shares of common stock, par value $0.04 per share, outstanding as of ~~August 6, 2018~~May 3, 2019 was ~~25,723,135~~34,400,594.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE ~~SIX~~THREE MONTHS ENDED ~~JUNE 30, 2018~~MARCH 31, 2019

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		Page
PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	3
	Consolidated Statements of Operations (unaudited) for the three ~~and six~~ months ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	4
	Consolidated Statements of Cash Flows (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2019 and March 2018	6
	Notes to the Consolidated Financial Statements (unaudited)	78
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2224
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	33 32

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	33 32
Item 1A.	Risk Factors	33 32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34 33
Item 3.	Defaults upon Senior Securities	34 33
Item 4.	Mine Safety Disclosures	34 33
Item 5.	Other Information	34 33
Item 6.	Exhibits	35 34

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

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Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)


	June 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018

	(unaudited)				(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	—	$	—
Accounts receivable, net		10,927		13,059		11,530		11,531
Prepaid expenses		1,540		1,892		468		1,303
Current derivative asset		161		822		1,371		4,600
Other current assets						112		—
Total current assets		12,628		15,773		13,481		17,434
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		1,194,753		1,239,662		1,096,714		1,095,417
Unproved properties		27,249		35,243		35,538		34,612
Other property and equipment		1,272		1,272		1,331		1,314
Accumulated depreciation, depletion and amortization		(883,321)		(930,220)		(905,437)		(898,169)
Total property, plant and equipment, net		339,953		345,957		228,146		233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates		18,696		18,464		6,053		5,743
Long-term derivative asset		152		—
Deferred tax asset		424		424		—		424
Other		595		835
Other non-current assets						352		357
Total other non-current assets		19,867		19,723		6,405		6,524
TOTAL ASSETS	$	372,448	$	381,453	$	248,032	$	257,132

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	42,111	$	46,755	$	32,188	$	39,506
Current derivative liability		2,951		1,765		839		422
Current asset retirement obligations		1,209		2,017		1,373		1,329
Current portion of long-term debt						65,552		60,000
Total current liabilities		46,271		50,537		99,952		101,257
NON-CURRENT LIABILITIES:
Long-term debt		80,827		85,380		—		—
Long-term derivative liability		915		300
Asset retirement obligations		19,722		20,388		12,108		12,168
Other long term liabilities		3,541		248		3,421		3,318
Total non-current liabilities		105,005		106,316		15,529		15,486
Total liabilities		151,276		156,853		115,481		116,743
COMMITMENTS AND CONTINGENCIES (NOTE 11)
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 31,156,772 shares issued and 25,739,282 shares outstanding at June 30, 2018, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017		1,235		1,223
Common stock, $0.04 par value, 50 million shares authorized, 39,925,092 shares issued and 34,416,727 shares outstanding at March 31, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018						1,585		1,573
Additional paid-in capital		305,523		302,527		340,935		339,981
Treasury shares at cost (5,417,490 shares at June 30, 2018 and 5,367,755 shares at December 31, 2017)		(128,778)		(128,583)
Retained earnings		43,192		49,433
Treasury shares at cost (5,508,365 shares at March 31, 2019 and 5,458,950 shares at December 31, 2018)						(129,216)		(129,030)
Retained earnings (deficit)						(80,753)		(72,135)
Total shareholders’ equity		221,172		224,600		132,551		140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	372,448	$	381,453	$	248,032	$	257,132

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended				Six Months Ended				Three Months Ended
	June 30,				June 30,				March 31,
	2018		2017		2018		2017		2019		2018
	(unaudited)				(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	9,607	$	6,483	$	18,418	$	12,025	$	6,406	$	8,811
Natural gas sales		5,848		11,135		14,457		22,275		5,642		8,609
Natural gas liquids sales		2,993		2,658		6,010		5,400		1,963		3,017
Total revenues		18,448		20,276		38,885		39,700		14,011		20,437
EXPENSES:
Operating expenses		6,478		6,329		13,405		13,162		5,192		6,927
Exploration expenses		394		284		863		375		224		469
Depreciation, depletion and amortization		9,498		12,714		19,983		24,485		7,556		10,485
Impairment and abandonment of oil and gas properties		777		1,401		4,104		1,431		587		3,327
General and administrative expenses		5,354		5,833		12,080		12,429		5,005		6,726
Total expenses		22,501		26,561		50,435		51,882		18,564		27,934
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates, net of income taxes		(475)		166		232		1,950
Gain from investment in affiliates, net of income taxes										30		707
Gain (loss) from sale of assets		1,370		(420)		10,817		2,520		(12)		9,447
Interest expense		(1,262)		(925)		(2,671)		(1,684)		(1,092)		(1,409)
Gain (loss) on derivatives, net		(2,610)		1,487		(3,642)		4,583
Loss on derivatives, net										(2,878)		(1,032)
Other income (expense)		3		61		882		(27)		(86)		879
Total other income (expense)		(2,974)		369		5,618		7,342		(4,038)		8,592
NET LOSS BEFORE INCOME TAXES		(7,027)		(5,916)		(5,932)		(4,840)
NET INCOME (LOSS) BEFORE INCOME TAXES										(8,591)		1,095
Income tax provision		(151)		(118)		(309)		(309)		(27)		(158)
NET LOSS	$	(7,178)	$	(6,034)	$	(6,241)	$	(5,149)
NET LOSS PER SHARE:
NET INCOME (LOSS)									$	(8,618)	$	937
NET INCOME (LOSS) PER SHARE:
Basic	$	(0.29)	$	(0.24)	$	(0.25)	$	(0.21)	$	(0.26)	$	0.04
Diluted	$	(0.29)	$	(0.24)	$	(0.25)	$	(0.21)	$	(0.26)	$	0.04
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		24,933		24,671		24,863		24,639		33,770		24,793
Diluted		24,933		24,671		24,863		24,639		33,770		24,841

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Six Months Ended				Three Months Ended
	June 30,				March 31,
	2018		2017		2019		2018

	(unaudited)				(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,241)	$	(5,149)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income (loss)					$	(8,618)	$	937
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		19,983		24,485		7,556		10,485
Impairment of natural gas and oil properties		3,890		1,400		483		3,097
Exploration recovery		—		(232)
Gain on sale of assets		(10,817)		(2,520)
Deferred income taxes						424		—
Loss (gain) on sale of assets						12		(9,447)
Gain from investment in affiliates		(232)		(1,950)		(30)		(707)
Stock-based compensation		3,008		3,078		1,052		1,424
Unrealized loss (gain) on derivative instruments		2,311		(4,327)
Unrealized loss on derivative instruments						3,646		519
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables		2,132		5,044
Decrease (increase) in prepaids		352		(402)
Decrease in inventory		—		123
Decrease (increase) in accounts receivable & other receivables						146		(642)
Decrease in prepaids						835		940
Decrease in accounts payable & advances from joint owners		(2,027)		(41)		(4,299)		(6,053)
Decrease in other accrued liabilities		(2,618)		(1,260)		(826)		(1,921)
Increase (decrease) in income taxes payable, net		229		(201)
Increase in income taxes receivable, net						(424)		—
Increase in income taxes payable, net						27		158
Other		3,293		61		(123)		3,279
Net cash provided by operating activities	$	13,263	$	18,109
Net cash provided by (used in) operating activities					$	(139)	$	2,069
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	$	(30,077)	$	(35,553)	$	(5,124)	$	(16,244)
Additions to furniture & equipment		—		(39)		(17)		—
Sale of furniture & equipment		—		12
Sale of oil & gas properties		21,562		670		—		20,965
Net cash used in investing activities	$	(8,515)	$	(34,910)
Net cash provided by (used in) investing activities					$	(5,141)	$	4,721
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	130,677	$	113,506	$	37,025	$	74,832
Repayments under credit facility		(135,230)		(96,544)		(31,473)		(81,551)
Net costs from equity offering						(86)		—
Purchase of treasury stock		(195)		(161)		(186)		(71)
Net cash provided by (used in) financing activities	$	(4,748)	$	16,801	$	5,280	$	(6,790)
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	—	$	—	$	—	$	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—		—		—		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—	$	—	$	—	$	—

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the three months ended March 31, 2019

(in thousands, except number of shares)


				Additional						Total					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		Earnings		Equity
	(unaudited)											(unaudited)
Balance at December 31, 2017	25,505,715	$	1,223	$	302,527	$	(128,583)	$	49,433	$	224,600
Balance at December 31, 2018												34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering costs												—		—		(86)		—		—		(86)
Treasury shares at cost	(49,735)		—		—		(195)		—		(195)	(49,415)		—		—		(186)		—		(186)
Restricted shares activity	283,302		12		(12)		—		—		—	307,650		12		(12)		—		—		—
Stock-based compensation	—		—		3,008		—		—		3,008	—		—		1,052		—		—		1,052
Net loss	—		—		—		—		(6,241)		(6,241)	—		—		—		—		(8,618)		(8,618)
Balance at June 30, 2018	25,739,282	$	1,235	$	305,523	$	(128,778)	$	43,192	$	221,172
Balance at March 31, 2019												34,416,727	$	1,585	$	340,935	$	(129,216)	$	(80,753)	$	132,551

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the three months ended March 31, 2018

(in thousands, except number of shares)


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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Business

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

The following table lists the Company’s primary producing areas as of ~~June 30, 2018:~~March 31, 2019:

Location		Formation
Gulf of Mexico		Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas		Wolfcamp
Madison and Grimes counties, Texas		Woodbine (Upper Lewisville)
~~Pecos~~Zavala and Dimmit counties, Texas		Buda / Eagle Ford / Georgetown
San Augustine County, Texas		~~Southern Delaware Basin (Wolfcamp)~~Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast		Conventional and smaller unconventional formations
~~Zavala and Dimmit counties, Texas~~		~~Buda / Eagle Ford~~
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 six months ended June 30, 2018.~~all periods shown in this report.

The ~~Company’s 2018 capital program~~Company has recently been focused on the development of ~~the Company’s~~its ~~16,500 gross (6,800 net) acres~~Southern Delaware Basin acreage in Pecos County, Texas, which is expected to continue to generate positive returns on its drilling investment in the current price environment. As of March 31, 2019, the Company was producing from twelve wells over its 17,700 gross operated (8,200 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.~~Southern Delaware Basin. Additionally,~~

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

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, ~~2017~~2018 (the ~~“2017~~“2018 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the ~~2017~~2018 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report.

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information,

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

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The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company, ~~(“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, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for ~~the Company’s~~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, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future

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production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized $2.7 million in non-cash proved property impairment charges for the six months ended June 30, 2018, including a $2.3 million impairment related to its Vermilion 170 offshore property during the three months ended March 31, 2018 and a $0.4 million impairment related to non-core onshore properties due to revised estimated reserves during the three months ended June 30, 2018. No impairment of proved properties was recognized during the ~~three and six months~~quarter ended ~~June 30, 2017.~~March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized impairment expense of approximately ~~$0.4~~$0.5 million and approximately ~~$1.2~~$0.8 million for ~~the three~~quarters ended March 31, 2019 and ~~six months ended June 30,~~ 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. The Company also recognized $1.4 million in impairment expense for the three and six months ended June 30, 2017 related to the partial impairment of two unused offshore platforms that were subsequently sold.

Net ~~Loss~~Income (Loss) Per Common Share

Basic net ~~loss~~income (loss) per common share is computed by dividing the net ~~loss~~income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net ~~loss~~income (loss) per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, ~~Performance Stock Units~~performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the ~~three months~~quarter ended ~~June 30, 2018,~~March 31, 2019, the Company excluded ~~1,133,534~~526,309 shares or units of potentially dilutive securities, as they were ~~antidilutive, and excluded 1,197,029 potentially dilutive securities for the six months ended June 30, 2018, as they were~~ antidilutive. For the ~~three months~~quarter ended ~~June 30, 2017,~~March 31, 2018, the Company excluded ~~1,366,091~~670,210 shares or units of potentially dilutive securities, as they were ~~antidilutive, and excluded 1,367,242 potentially dilutive securities for the six months ended June 30, 2017, as they were~~ antidilutive.

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Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

Revenue Recognition

Adoption of ASC 606

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

Revenue from Contracts with Customers

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

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

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

Transaction Price Allocated to Remaining Performance Obligations

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

Contract Balances

The Company receives purchaser statements from the majority of ~~the Company’s~~its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice.

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Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

Prior Period Performance Obligations

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

Impact of Adoption of ASC 606

The Company has reviewed all of ~~the Company’s~~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 ~~the Company’s operating~~its results of operations for the ~~six months~~quarter ended ~~June 30, 2018.~~March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Recent Accounting Pronouncements

In ~~January~~August 2018, the ~~Financial Accounting Standards Board (“FASB”)~~FASB issued ~~Accounting Standards Update (“ASU”) 2018-01~~ASU 2018-13 – ~~Leases~~Fair Value Measurement (Topic ~~842): Land Easement Practical Expedient for Transition to~~820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic ~~842.~~820. The amendments in this update permit an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements (right of way payments) that exist or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. Right of way payments do not have a material impact on the Company’s results of operations and the Company plans to elect the practical expedient to evaluate right of way payments prospectively on adoption of Topic 842.

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~~all entities for fiscal years, ~~beginning after December 15, 2018, including~~and interim periods within those fiscal years; early application is permitted. The Company is currently collating all leases and potential leases for evaluation and will continue to assess the impact this may have on its financial position, results of operations and cash flows.

~~3. Acquisitions and Dispositions~~

~~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~~years, beginning after ~~removal of the asset retirement obligations associated with the sold properties.~~

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

3. Acquisitions and Dispositions

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

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

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.

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 ~~June 30, 2018.~~March 31, 2019. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Fair value information for financial assets and liabilities was as follows as of ~~June 30, 2018~~March 31, 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	$	313	$	—	$	313	$	—	$	1,371	$	—	$	1,371	$	—
Commodity price contracts - liabilities	$	(3,866)	$	—	$	(3,866)	$	—	$	(839)	$	—	$	(839)	$	—

Derivatives listed above are recorded in “Current ~~derivative asset or liability” and “Long-term~~ derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in ~~"Gain (loss)~~"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 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 ~~June 30, 2018,~~March 31, 2019, the Company's derivative contracts were all with certain members of its ~~credit facility~~Credit Facility lending group, which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Estimates of the fair value of financial instruments are made in accordance with the requirements of ~~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

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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~~

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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 possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.

Asset Retirement Obligations

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

5. Derivative Instruments

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

As of ~~June 30, 2018,~~March 31, 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. 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

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records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in ~~"Gain (loss)~~“Loss on derivatives, ~~net"~~net” on the consolidated statements of operations.

As of ~~June 30, 2018,~~March 31, 2019, the following financial derivative instruments were in place (fair value in thousands):

~~Commodity~~

~~Period~~

~~Derivative~~

~~Volume/Month~~

~~Price/Unit~~

~~Fair Value~~

~~Natural Gas~~

~~July 2018~~

~~Swap~~

~~370,000 MMBtus~~

~~3.07~~ ~~(1)~~

~~Natural Gas~~

~~Aug 2018 - Oct 2018~~

~~Swap~~

~~70,000 MMBtus~~

~~3.07~~ ~~(1)~~

~~Natural Gas~~

~~Nov 2018 - Dec 2018~~

~~Swap~~

~~320,000 MMBtus~~

~~3.07~~ ~~(1)~~

~~Oil~~

~~July 2018 - Oct 2018~~

~~Collar~~

~~20,000 Bbls~~

~~52.00 - 56.85~~ ~~(2)~~

~~(1,466)~~

~~Oil~~

~~Nov 2018 - Dec 2018~~

~~Collar~~

~~15,000 Bbls~~

~~52.00 - 56.85~~ ~~(2)~~

~~(484)~~

~~Oil~~

~~July 2018 - Dec 2018~~

~~Collar~~

~~2,000 Bbls~~

~~52.00 - 58.76~~ ~~(3)~~

~~(149)~~

~~Oil~~

~~July 2018~~

~~Collar~~

~~6,000 Bbls~~

~~58.00 - 68.00~~ ~~(2)~~

~~(54)~~

~~Oil~~

~~Nov 2018 - Dec 2018~~

~~Collar~~

~~5,000 Bbls~~

~~58.00 - 68.00~~ ~~(2)~~

~~(68)~~

~~Oil~~

~~July 2018~~

~~Swap~~

~~6,000 Bbls~~

~~70.11~~ ~~(3)~~

~~(21)~~

~~Oil~~

~~Aug 2018 - Oct 2018~~

~~Swap~~

~~3,000 Bbls~~

~~70.11~~ ~~(3)~~

~~(7)~~

~~Oil~~

~~Nov 2018 - Dec 2018~~

~~Swap~~

~~6,000 Bbls~~

~~70.11~~ ~~(3)~~

~~Oil~~

~~Jan 2019 - Dec 2019~~

~~Collar~~

~~4,000 Bbls~~

~~52.00 - 59.45~~ ~~(3)~~

~~(373)~~

~~Oil~~

~~Jan 2019 - Dec 2019~~

~~Collar~~

~~7,000 Bbls~~

~~50.00 - 58.00~~ ~~(2)~~

~~(1,037)~~

~~Oil~~

~~Jan 2019 - July 2019~~

~~Swap~~

~~6,000 Bbls~~

~~66.10~~ ~~(3)~~

~~(14)~~

~~Total net fair value of derivative instruments~~

~~(3,553)~~



Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	April 2019 - July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	98
Natural Gas	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	(14)
Natural Gas	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	(170)

Oil	April 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(499)
Oil	April 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(103)
Oil	April 2019 - June 2019	Collar	12,000	Bbls	$	70.00	-	76.25	(3)	$	350

Oil	April 2019 - July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	137

Oil	July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	138
Oil	Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	311
Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	284
		Total net fair value of derivative instruments								$	532

(1)

Based on Henry Hub NYMEX natural gas prices.

(2)

Based on Argus Louisiana Light Sweet crude oil prices.

(3)

Based on West Texas Intermediate crude oil prices.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of ~~June 30, 2018~~March 31, 2019 (in thousands):


	Gross		Netting (1)		Total		Gross		Netting (1)		Total
Assets	$	313	$	—	$	313	$	1,371	$	—	$	1,371
Liabilities	$	(3,866)	$	—	$	(3,866)	$	(839)	$	—	$	(839)

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

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, ~~2017~~2018 (in thousands):


	Gross		Netting (1)		Total		Gross		Netting (1)		Total
Assets	$	1,188	$	(1,188)	$	—	$	4,600	$	—	$	4,600
Liabilities	$	(2,431)	$	1,188	$	(1,243)	$	(422)	$	—	$	(422)

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

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The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the ~~three~~quarters ended March 31, 2019 and ~~six months ended June 30,~~ 2018 ~~and 2017~~ (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2018		2017		2018		2017		2019		2018
Crude oil contracts	$	(1,123)	$	367	$	(1,711)	$	537	$	655	$	(588)
Natural gas contracts		305		68		380		(281)		113		75
Realized gain (loss)	$	(818)	$	435	$	(1,331)	$	256	$	768	$	(513)

Crude oil contracts	$	(1,311)	$	293	$	(1,594)	$	817	$	(3,443)	$	(284)
Natural gas contracts		(481)		759		(717)		3,510		(203)		(235)
Unrealized gain (loss)	$	(1,792)	$	1,052	$	(2,311)	$	4,327
Gain (loss) on derivatives, net	$	(2,610)	$	1,487	$	(3,642)	$	4,583
Unrealized loss									$	(3,646)	$	(519)
Loss on derivatives, net									$	(2,878)	$	(1,032)

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


Commodity	Period	Derivative	Volume/Month		Price/Unit
Natural Gas	Jan 2020 - March 2020	Swap	425,000	Mmbtus	$	2.84	(1)

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

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

Oil	May 2019 - Dec 2019	Swap	2,400	Bbls	$	61.72	(2)

Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(2)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(2)

(1)

Based on Henry Hub NYMEX natural gas prices.

(2)

Based on West Texas Intermediate crude oil prices.

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

6. Stock-Based Compensation

Restricted Stock

During the quarter ended March 31, 2019, the Company granted 307,650 shares of restricted common stock, which vest over three years, to employees and executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2019, was $3.20 per share, with a total fair value of approximately $1.0 million and no adjustment for an estimated weighted average forfeiture rate. There were no forfeitures of restricted stock during the quarter ended March 31, 2019. The Company recognized approximately ~~$3.0~~$1.0 million ~~and $3.1 million~~ in restricted stock compensation expense during the ~~six months~~quarter ended ~~June 30, 2018 and 2017, respectively, for equity awards~~March 31, 2019 related to restricted stock granted to its officers, employees and directors. As of ~~June 30, 2018,~~March 31, 2019, an additional ~~$4.7~~$1.9 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of ~~1.7~~2.0 years. ~~This includes expense related to restricted stock, Performance Stock Units (“PSUs”)~~Approximately 1.2 million shares remained available for grant under the Second Amended and ~~stock options.~~

~~Restricted Stock~~ Restated 2009 Incentive Compensation Plan as of March 31, 2019, assuming PSUs (as defined below) are settled at 100% of target.

During the ~~six months~~quarter ended ~~June 30,~~March 31, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. ~~Additionally, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan.~~ The weighted average fair value of the restricted shares granted during the ~~six months~~quarter ended ~~June 30,~~March 31, 2018, was ~~$3.76~~$3.57 per share, with a total fair

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value of approximately ~~$1.2~~$0.8 million ~~with~~and no adjustment for an estimated weighted average forfeiture rate. During the ~~six months~~quarter ended ~~June 30,~~March 31, 2018, ~~24,980~~19,668 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the ~~six months~~quarter ended ~~June 30,~~March 31, 2018 was approximately ~~$222 thousand. Approximately 1.2~~$0.2 million. The Company recognized approximately $1.0 million ~~shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of June 30, 2018, assuming PSUs are settled at 100% of target.~~

During the six months ended June 30, 2017, the Company granted 43,000 shares of restricted common stock, which vest over three years, to newly hired employees as part of their overall compensation package. Additionally, the Company granted 338,076 shares ofin restricted stock ~~to existing employees, which vest over three years, as part of their overall~~ compensation package, and 74,325 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares grantedexpense during the ~~six months~~quarter ended June 30, 2017, was $7.56 with a total fair value of approximately $3.4 million after adjustment for an estimated weighted average forfeiture rate of 5.7%. During the six months ended June 30, 2017, 63,490March 31, 2018 related to restricted ~~shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2017 was approximately $688 thousand.~~stock granted to its officers, employees and directors.

Performance Stock Units

During the six months ended June 30, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, at a weighted average fair value of $7.69 per unit. During the six months ended June 30, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit. An additional 160,908 PSUs were granted to executive officers, as part of their overall compensation package, at a value of $13.91 per unit during the six months ended June 30, 2017. All fair value prices were determined using the Monte Carlo simulation model. During the six months ended June 30, 2018 and 2017, 19,300 and 34,899 PSUs were forfeited by former employees, respectively. 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

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

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

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the ~~six months~~quarters ended ~~June 30,~~March 31, 2019 and 2018, ~~and 2017,~~ 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 ~~six months~~quarters ended ~~June 30, 2018~~March 31, 2019 or ~~2017.~~2018.

During the ~~six months~~quarter ended ~~June 30, 2018, no stock options were exercised or forfeited. During the six months ended June 30, 2017,~~March 31, 2019, no stock options were exercised and stock options for ~~14,586~~12,052 shares ~~of common stock~~ were forfeited by former employees. During the quarter ended March 31, 2018, no stock options were exercised or forfeited.

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7. Leases

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

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

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

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

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

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


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

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Present value of lease liabilities

211

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


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

(1)

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

(2)

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

(3)

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

(4)

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

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

8. Other Financial Information

The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):


	June 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Accounts receivable:
Trade receivables	$	5,316	$	6,565	$	5,371	$	6,052
Receivable for Alta Resources Distribution		1,993		1,993
Receivable for Alta Resources distribution						1,712		1,993
Joint interest billings		3,887		4,030		4,472		3,833
Income taxes receivable		424		424		848		424
Other receivables		88		828		121		223
Allowance for doubtful accounts		(781)		(781)		(994)		(994)
Total accounts receivable	$	10,927	$	13,059	$	11,530	$	11,531

Prepaid expenses and other:
Prepaid insurance	$	920	$	1,177	$	256	$	792
Other		620		715		212		511
Total prepaid expenses and other	$	1,540	$	1,892	$	468	$	1,303

Accounts payable and accrued liabilities:
Royalties and revenue payable	$	18,888	$	18,181	$	13,615	$	17,986
Advances from partners		4,145		2,243		2,101		1,785
Accrued exploration and development		8,171		8,400		2,531		4,751
Accrued acquisition costs						3,763		4,352
Trade payables		4,726		9,559		3,099		3,385
Accrued general and administrative expenses		2,322		2,960		2,403		2,545
Accrued operating expenses		1,662		1,654		1,229		1,801
Other accounts payable and accrued liabilities		2,197		3,758		3,447		2,901
Total accounts payable and accrued liabilities	$	42,111	$	46,755	$	32,188	$	39,506

1518

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Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the ~~six months~~quarters ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~ (in thousands):


		Six Months Ended June 30,				Three Months Ended March 31,
		2018		2017		2019		2018
Cash payments:
Interest payments	$	2,596	$	1,491	$	1,046	$	1,448
Income tax payments	$	81	$	498	$	40	$	—
Non-cash investing activities in the consolidated statements of cash flows:
Decrease in accrued capital expenditures	$	(229)	$	(7,935)
Increase (decrease) in accrued capital expenditures					$	(2,220)	$	3,669

8.9. Investment in Exaro Energy III LLC

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

The following table (in thousands) presents unaudited condensed balance sheet data for Exaro as of June 30, 2018 and December 31, 2017. The balance sheet data was derived from Exaro’s balance sheet as of June 30, 2018 and December 31, 2017 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 ~~June 30, 2018~~March 31, 2019 was approximately ~~$18.6~~$6.1 million.

June 30, 2018

December 31, 2017

Current assets (1)

$
12,910

$
17,063

Non-current assets:

Net property and equipment

77,837

82,450

Gas processing deposit

1,150

1,150

Other non-current assets

445

390

Total non-current assets

79,432

83,990

Total assets

$
92,342

$
101,053

Current liabilities

$
4,415

$
6,199

Non-current liabilities:

Long-term debt

32,411

40,375

Other non-current liabilities

3,958

3,858

Total non-current liabilities

36,369

44,233

Members' equity

51,558

50,621

Total liabilities & members' equity

$
92,342

$
101,053

~~(1)~~

~~Approximately $9.6 million and $12.8 million of current assets as of June 30, 2018 and December 31, 2017, respectively, is cash.~~

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The following table (in thousands) presents the unaudited condensed results of operations for Exaro for the three and six months ended June 30, 2018 and 2017. The results of operations for the three and six months ended June 30, 2018 and 2017 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company’s share in Exaro’s results of operations recognized for the ~~three months~~quarters ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~ was a ~~loss~~gain of ~~$0.5~~$0.3 million, net of no tax expense, and a gain of $0.2 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the six months ended June 30, 2018 and 2017 was a gain of $0.2 million, net of no tax expense, and a gain of $2.0$0.7 million, net of no tax expense, respectively.

Three Months Ended June 30,

Six Months Ended June 30,


2018

2017

2018

2017

Production:

Oil (thousand barrels)

21

28

43

54

Gas (million cubic feet)

1,946

2,272

3,881

4,580

Total (million cubic feet equivalent)

2,072

2,442

4,139

4,902

Oil and natural gas sales

$
5,955

$
7,844

$
12,838

$
17,016

Gain (loss) on derivatives

(582)

841

1,044

3,402

Less:

Lease operating expenses

3,278

4,767

6,668

7,987

Depreciation, depletion, amortization & accretion

2,321

2,249

4,729

4,591

General & administrative expense

351

874

705

1,606

Income (loss) from continuing operations

(577)

795

1,780

6,234

Net interest expense

(636)

(328)

(1,079)

(952)

Net income (loss)

$
(1,213)

$
467

$
701

$
5,282

~~Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes.~~10. Indebtedness

~~9. Long-Term Debt~~

~~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”)~~, the maturity of which has been extended by subsequent amendment to~~ currently matures on October 1, 2019. The borrowing base under the facility is redetermined each November 1 and ~~May.~~May 1. As of ~~June 30, 2018,~~March 31, 2019, the borrowing base under the ~~RBC~~ Credit Facility was ~~$110 million, but was reduced to $105 million effective August 1, 2018, as agreed to during the~~$90 million. The Company is currently going through its regularly scheduled May ~~2018 redetermination.~~redetermination process.

As of ~~June 30,~~March 31, 2019, the Company had approximately $65.6 million outstanding under the Credit Facility and $1.9 million in an outstanding letter of credit. As of December 31, 2018, the Company had approximately ~~$80.8~~$60.0 million outstanding under the ~~RBC~~ Credit Facility and $1.9 million in outstanding letters of credit. As of ~~December~~March 31, ~~2017, the Company had approximately $85.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of June 30, 2018,~~2019, borrowing availability under the ~~RBC~~ Credit Facility was ~~$27.3~~$22.6 million.

The ~~RBC~~ 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 six months~~quarter ended ~~June 30, 2018~~March 31, 2019 was approximately ~~$1.3 million and $2.7 million, respectively.~~$1.1 million. Total interest expense under the ~~RBC~~ Credit Facility, including commitment fees, for the ~~three and six months~~quarter ended ~~June 30, 2017~~March 31, 2018 was approximately ~~$0.9 million and $1.7 million, respectively.~~$1.4 million.

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

The Credit Facility contains restrictive covenants which, among other things, ~~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. The Credit Facility ~~Agreement. As of June 30, 2018, the Company was~~

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in compliance with all but the Current Ratio covenant under the RBC Credit Facility, although the Company obtained a waiver for such non-compliance effective as of June 30, 2018. The Company intends to review the amount and timing of its remaining 2018 capital expenditure program after the drilling of its next three Southern Delaware Basin wells. The Company’s ability or commitment to continue its capital expenditure program will be determined based on its evaluation of well results, commodity prices (including the impact of the dramatic increase in the Midland-Cushing oil price differentials) and the availability of capital. The RBC Credit Facilityalso contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants, ~~including the current ratio covenant,~~ bankruptcy, insolvency or change of control events. As of March 31, 2019, the Company was in compliance with all of its covenants under the Credit Facility.

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

Over the past several months, the Company has been in ~~effect at June 30, 2018~~discussions with its current lenders and ~~December 31, 2017 was 5.8% and 5.2%, 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 for future capital expenditures, and in

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

~~10.~~11. Income Taxes

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2018		2017		2018		2017		2019		2018
Current tax provision:
Federal	$	—	$	—	$	—	$	—	$	—	$	—
State		151		118		309		309		27		158
Total	$	151	$	118	$	309	$	309	$	27	$	158
Total tax provision:
Federal	$	—	$	—	$	—	$	—	$	—	$	—
State		151		118		309		309		27		158
Total income tax provision	$	151	$	118	$	309	$	309	$	27	$	158

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the ~~six months~~quarter ended ~~June 30, 2018,~~March 31, 2019, the Company ~~continues~~continued to ~~take~~record a full valuation allowance against its net deferred tax ~~asset except for the portion attributable to the estimated refundable Alternative Minimum Tax (“AMT”) credit.~~assets. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company ~~completed the accounting~~expects that its effective income tax rate for ~~the effects~~2019 will be less than 1% consisting entirely of ~~the Act during 2017. The Company’s financial statements for the six months ended June 30, 2018 reflect certain effects~~state of the Act which includes the reduced corporate tax of 21%, elimination of the corporate AMT, limitations on the use of interest expense and net operating losses, accelerated expensing of tangible property, as well as other changes.Louisiana income taxes.

~~11.~~In the quarter ended December 31, 2018, the Company experienced an Ownership Change as described in Internal Revenue Code section 382 as a result of a completed follow-on equity offering. Management estimates that as a result of this Ownership Change, its future Net Operating Loss (NOL) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year, plus the amount of any built in gains (essentially: the excess of the fair market value of properties over their respective income tax bases) recognized in the five years after 2018. As a result of these limitations, it is likely that a substantial portion of the Company’s pre-2018 NOLs will expire unused. Due to the presence of the valuation allowance from prior years, this event resulted in no net charge to earnings. The Company is performing additional analysis related to this matter which will be finalized when the Company files its 2018 U.S. federal income tax return later this year.

12. Commitments and Contingencies

Legal Proceedings

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

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In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the

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Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of ~~Appeals. In~~Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. ~~The~~In the first quarter of 2018, the Company ~~previously~~ filed a motion for rehearing with the Court of Appeals, which was ~~recently~~ denied, as expected. The Company continues to vigorously defend this lawsuit and ~~is currently preparing~~has filed a petition requesting a review by the Texas Supreme ~~Court.~~Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. The Company is awaiting a response from the Texas Supreme Court as to whether it intends to review the case. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected ~~the~~ 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 for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million, although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. OnIn December ~~14,~~ 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff has ~~indicated that it intends to file~~filed a petition requesting that the matter be reviewed by the Texas Supreme ~~Court.~~Court; the parties are awaiting a response from the Texas Supreme Court as to whether it intends to review the case. The Company continues to vigorously defend this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit.

While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.

Throughput Contract Commitment

The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. ~~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 fees of $0.2 million and $0.3 million during the quarters ended March 31, 2019 and 2018, respectively. As of ~~June 30, 2018,~~March 31, 2019, the Company estimates that the net deficiency fee will be approximately $1.0 million ~~annually~~ for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. ~~As of June 30, 2018, based upon the current commodity price market and the Company’s short term strategic drilling plans, the~~The Company has ~~recorded a $0.7~~now accrued the total estimated remaining $2.0 million loss contingency through ~~December~~the expiration of the contract on March 31, ~~2018. The Company will assess this commitment in the fourth quarter when its development plans for this area are addressed in the approved budget for 2019.~~2020.

1921

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Available Information

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”). This report should be read together with our 2018 Annual Report on Form 10-K. We are not including the information on our website as a part of, or incorporating it by reference into, this ~~Report.~~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 be”~~“should”, ~~“will be”~~“will”, “believe”, “plan”, “intend”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in our 2018 Annual Report on Form 10-K ~~and Quarterly Report on Form 10-Q for the quarter ended March 31, 2018~~ and those factors summarized below:

our ability to continue as a going concern;

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

our financial position;

our business strategy, including ~~outsourcing;~~execution of any changes in our strategy;

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

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

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

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

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

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

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

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

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

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

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

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

interest rate volatility;

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

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

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

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

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

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

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

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

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

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

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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; ~~and~~

the ability to obtain adequate insurance coverage on commercially reasonable ~~terms.~~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. ~~All~~You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.

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

~~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.

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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 ~~2017~~2018 Form 10-K, previously filed with the Securities and Exchange Commission ("SEC").

Overview

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

The following table lists our primary producing areas as of ~~June 30, 2018:~~March 31, 2019:

Location		Formation
Gulf of Mexico		Offshore Louisiana - water depths less than 300 feet
Southern Delaware Basin, Pecos County, Texas		Wolfcamp
Madison and Grimes counties, Texas		Woodbine (Upper Lewisville)
~~Pecos~~Zavala and Dimmit counties, Texas		Buda / Eagle Ford / Georgetown
San Augustine County, Texas		~~Southern Delaware Basin (Wolfcamp)~~Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast		Conventional and smaller unconventional formations
~~Zavala and Dimmit counties, Texas~~		~~Buda / Eagle Ford~~
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 and six months ended June 30, 2018.~~all periods shown in this report.

Capital Expenditures

Our ~~2018~~2019 capital program has focused, and will continue to focus, on the development of our ~~16,500~~17,700 gross ~~(6,800~~operated (8,200 total net) acres in ~~the~~ our Southern Delaware ~~Basin.~~ Basin acreage in Pecos County, Texas. Until a sustained improvement in commodity prices occurs, we will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand our presence in those existing areas. Despite challenges experienced throughout the Southern Delaware Basin related to constrained production takeaway capacity, and the adverse impact on commodity price differentials, we still generate positive returns to date on our drilling investment. We continuously monitor the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, will make adjustments to our capital program as the year progresses.

Additionally, we will continue to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, ~~maintain core leases and continue to identify~~while also searching for new resource ~~potential opportunities internally and, where appropriate and assuming we have adequate capital to do so, through acquisition.~~acquisition opportunities. Acquisition efforts will ~~typically~~ be focused on areas in which we can leverage our geological and operational experience and expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to economically grow production and add reserves. We continuously monitor the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, make adjustments to our strategy as the year progresses.

~~Capital Expenditures~~

Our Southern Delaware Basin acreage has generated, and is expected to continue to generate, positive returns on our drilling investment in the current commodity price environment. We currently expect to drill three wells and complete two for the remainder of the year, after which we intend to review the amount and timing of our remaining 2018 capital expenditure program. Our ability or commitment to continue our capital expenditure program will be determined based on our evaluation of well results, commodity prices (including the impact of the dramatic increase in the Midland-Cushing oil price differentials) and the availability of capital. We do not currently expect to devote meaningful capital to the development of our other areas, but expect to devote capital to those areas to fulfill leasehold commitments and preserve core acreage to the extent we have available capital to do so. We will continue to evaluate new organic opportunities for growth and will continue to evaluate pursuing stressed or distressed acquisition opportunities that may arise in this low commodity price environment. See “Capital Resources and Liquidity” for a further discussion of our existing credit facility and possible refinancing.

Southern Delaware Basin (West Texas)

~~Our first five Southern Delaware Basin wells were brought on production during 2017. During the six months ended June 30,~~As of December 31, 2018, we ~~brought~~had nine wells producing from the Wolfcamp A, three ~~additional~~ wells onproducing from the Wolfcamp B, and a fourth well drilled in the Wolfcamp B that will be completed later in 2019.

On March 19, 2019, we spud the Iron Snake #1H, targeting the Wolfcamp B formation. This well was drilled to a total measured depth of 20,511 feet, including a 10,112 foot lateral. Due to infrastructure required to be built in this portion of our acreage, completion operations are expected to begin in August 2019, with first production ~~the Ragin Bull #3H (Wolfcamp A), River Rattler #1H (Wolfcamp B) and Ragin Bull #2H (Wolfcamp B), with average maximum 30 day initial production rates (“IP”) of~~expected in October 2019.

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~~1,070 Boed (67% oil), 1,225 Boed (74% oil), and 734 Boed (66% oil), respectively. The River Rattler~~

On April 24, 2019, we spud the American Hornet #1H, our first Wolfcamp B test, has had the best 24-hour IP (1,416 Boed) and 30-day IP of all our wells in the Southern Delaware Basin. We continue to identify cost efficiencies in our drilling efforts, as evidenced by the fact that these three wells averaged less than 27 days from spud to total measured depth (“TMD”).

~~In July 2018, we brought two more wells on production which were drilled from a common pad, the Sidewinder #1H (49% WI, 37% NRI)~~ targeting the Wolfcamp A ~~formation and the Gunner #3H (47% WI, 35% NRI) targeting the Wolfcamp B. The Sidewinder #1H was~~formation. This well is expected to be drilled to a ~~TMD~~total measured depth of ~~20,550~~approximately 20,100 feet, including a ~~10,500~~10,000 foot lateral, ~~and had a 30-day IP of 368 Boed (70% oil). The Gunner #3H was drilled to a TMD of 20,167 feet, including a 10,067 foot lateral, and had a 30-day IP of 773 Boed (78% oil).~~

On July 1, 2018, we spud the Fighting Ace #2H (50% WI, 38% NRI) targeting the Wolfcamp A, which was drilled to a TMD of 20,560 feet, including a 10,598 foot lateral. Completion operations on this well arewith production expected to ~~commence~~begin in ~~mid-August,~~September 2019. For the remainder of the year, our capital expenditure budget calls for us to drill two more wells and complete a total of five wells, with ~~initial production expected in mid-September.~~

~~On August 2, 2018, we spud~~ the ~~General Paxton #1H (50% WI, 38% NRI) in~~next well to be the ~~southeast quadrant of our acreage position.~~Breakthrough State #1H. This well will target the Wolfcamp A formation and is expected to ~~have a TMD of approximately 20,000 feet, including a lateral of approximately 10,000 feet. From there, we expect to move the rig approximately five miles to the northwest and~~be spud ~~the River Rattler #4H. After that, we will evaluate our strategy for the remainder of the year, given the dramatic increase~~ in ~~the Midland-Cushing oil differentials in the area.~~May 2019.

Impairment of Long-Lived Assets

We recognized ~~$2.7 million in~~no impairment of proved properties during the ~~six months ended June 30, 2018, including a $2.3 million impairment of proved properties related to our Vermilion 170 offshore property during the three months~~quarter ended March 31, ~~2018 and a $0.4 million impairment of non-core onshore proved properties for the three months ended June 30, 2018.~~2019. Under GAAP, an impairment charge is required when the unamortized capital cost of any individual property within the Company’s producing property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves for that property. We recognized impairment expense of approximately ~~$0.4 million and approximately $1.2~~$0.5 million for the ~~three and six months~~quarter ended ~~June 30, 2018, respectively,~~March 31, 2019, related to impairment of certain non-core unproved properties primarily due to expiring ~~non-core~~ leases.

Going Concern Assessment

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

Summary Production Information

Our production for the ~~three months~~quarter ended ~~June 30, 2018~~March 31, 2019 was approximately ~~56%~~65% offshore and ~~44%~~35% onshore, volumetrically, and was comprised of 59% natural gas, ~~24%~~23% oil and ~~17%~~18% natural gas liquids. Our production for the three months ended ~~June 30, 2017~~March 31, 2018 was ~~68%~~64% offshore and ~~32%~~36% onshore, volumetrically, and was comprised of approximately ~~68%~~65% natural gas, ~~16%~~19% oil and 16% natural gas liquids.

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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


June 30, 2017

September 30, 2017

December 31, 2017

March 31, 2018

June 30, 2018

Offshore GOM

Dutch and Mary Rose (1)

36.3

32.2

30.8

29.0

21.0

Vermilion 170 (2)

3.1

4.2

3.5

3.0

2.7

South Timbalier 17 (3)

0.2

0.1

—

—

—

Southeast Texas (4)

8.2

7.8

7.5

7.3

6.4

South Texas (5)

5.6

4.6

5.8

5.3

4.5

West Texas

3.3

3.2

3.2

4.5

6.7

Other (6)

1.3

1.1

1.0

0.9

1.1

58.0

53.2

51.8

50.0

42.4


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

(1)

Includes a decreased production rate of 4.2 Mmcfe/d due to downtime related to compressor installation and maintenance during the three months ended June 30, ~~2018.~~

~~(2)~~

~~Includes~~2018 and a decreased production rate of ~~0.8~~0.5 Mmcfe/d due to temporary pipeline limitations during the three months ended ~~June 30, 2017.~~December 31, 2018. Our Vermilion 170 well was sold effective December 1, 2018 and produced at an average daily rate of 2.2 Mmcfe/d during 2018. Our GOM production was not materially affected by Hurricane Michael which passed through the northeastern GOM in October 2018.

~~(3)~~

~~South Timbalier 17 ceased production in August 2017.~~

~~(4)~~(2)

Includes Woodbine production from Madison and Grimes counties and conventional production in ~~others.~~

~~(5)~~

~~Includes~~others; Eagle Ford and Buda production from ~~Karnes,~~ Zavala and Dimmit ~~counties,~~counties; and ~~conventional~~wells in East Texas and Wyoming. Decrease in production ~~in others. Includes a decreased production rate of 0.7 Mmcfe/d during the three months ended June 30, 2018 due to Karnes County sale~~ during three months ended ~~March~~December 31, ~~2018.~~

~~(6)~~

~~Includes onshore wells~~2018 is primarily due to the Liberty and Hardin County property sale in ~~East Texas and Wyoming.~~November 2018.

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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 ~~June 30, 2018,~~March 31, 2019, Exaro had ~~647~~648 wells on production over its 5,760 gross acres (1,040 net), with a working interest between 2.4% and 32.5%. These wells were producing at a rate of approximately 2319 Mmcfe/d, net to Exaro. The current operator of these interests has applied for multiple drilling permits for horizontal wells that will be located on parts of our acreage. Exaro’s working interest in the drilling spacing units for the applied for horizontal wells ranges from 1% to 6%. As a result of our investment in Exaro, we recognized an investment ~~loss~~gain of approximately ~~$0.5~~$0.3 million, net of no tax expense, and an investment gain of $0.7 million, net of no tax expense, for the ~~three months~~quarters ended ~~June 30,~~March 31, 2019 and 2018, and an investment gain of $0.2 million, net of no tax expense, for the three months ended June 30, 2017. For the six months ended June 30, 2018 and 2017, we recognized an investment gain of approximately $0.2 million, net of no tax expense, and $2.0 million, net of no tax expense, respectively, as a result of our investment in Exaro.respectively. See Note 89 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.

Non-Core Asset Sales

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

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Results of Operations for the ~~Three~~Quarters ended March 31, 2019 and ~~Six Months Ended June 30,~~ 2018 ~~and 2017~~

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~~quarters ended March 31, 2019 and ~~six months ended June 30, 2018 and 2017.~~2018. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported operating expenses include production taxes, such as ad valorem and severance taxes.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2018		2017		%		2018		2017		%		2019		2018		%

Revenues (thousands):
Oil and condensate sales	$	9,607	$	6,483	48	%	$	18,418	$	12,025	53	%	$	6,406	$	8,811	(27)	%
Natural gas sales		5,848		11,135	(47)	%		14,457		22,275	(35)	%		5,642		8,609	(34)	%
NGL sales		2,993		2,658	13	%		6,010		5,400	11	%		1,963		3,017	(35)	%
Total revenues	$	18,448	$	20,276	(9)	%	$	38,885	$	39,700	(2)	%	$	14,011	$	20,437	(31)	%

Production:
Oil and condensate (thousand barrels)
Offshore GOM		18		33	(45)	%		37		55	(33)	%		13		19	(32)	%
Southeast Texas		29		38	(24)	%		62		82	(24)	%
South Texas		25		23	9	%		53		49	8	%
West Texas		70		37	89	%		122		46	165	%		64		52	24	%
Other		9		11	(18)	%		18		24	(25)	%
Other Onshore														48		69	(30)	%
Total oil and condensate		151		142	6	%		292		256	14	%		125		140	(11)	%
Natural gas (million cubic feet)
Offshore GOM		1,695		2,908	(42)	%		3,991		5,916	(33)	%		1,635		2,296	(29)	%
Southeast Texas		265		340	(22)	%		565		675	(16)	%
South Texas		197		276	(29)	%		431		605	(29)	%
West Texas		80		33	142	%		126		33	282	%		64		46	39	%
Other		42		50	(16)	%		79		106	(25)	%
Other Onshore														194		571	(66)	%
Total natural gas		2,279		3,607	(37)	%		5,192		7,335	(29)	%		1,893		2,913	(35)	%
Natural gas liquids (thousand barrels)
Offshore GOM		59		83	(29)	%		137		167	(18)	%		66		78	(15)	%
Southeast Texas		24		29	(17)	%		50		58	(14)	%
South Texas		10		16	(38)	%		24		30	(20)	%
West Texas		18		8	125	%		25		8	213	%		14		7	100	%
Other		—		—	—	%		—		1	(100)	%		18		40	(55)	%
Total natural gas liquids		111		136	(18)	%		236		264	(11)	%		98		125	(22)	%
Total (million cubic feet equivalent)
Offshore GOM		2,156		3,602	(40)	%		5,033		7,248	(31)	%		2,111		2,877	(27)	%
Southeast Texas		580		747	(22)	%		1,240		1,517	(18)	%
South Texas		412		509	(19)	%		890		1,083	(18)	%
West Texas		606		304	99	%		1,008		359	181	%		534		402	33	%
Other		100		115	(13)	%		187		250	(25)	%
Other Onshore														590		1,225	(52)	%
Total production		3,854		5,277	(27)	%		8,358		10,457	(20)	%		3,235		4,504	(28)	%

Daily Production:
Oil and condensate (thousand barrels per day)
Offshore GOM		0.2		0.4	(45)	%		0.2		0.3	(33)	%		0.1		0.2	(32)	%
Southeast Texas		0.3		0.4	(24)	%		0.3		0.5	(24)	%
South Texas		0.3		0.3	9	%		0.3		0.3	8	%
West Texas														0.7		0.6	24	%
Other Onshore														0.6		0.8	(30)	%
Total oil and condensate														1.4		1.6	(11)	%
Natural gas (million cubic feet per day)
Offshore GOM														18.2		25.5	(29)	%
West Texas														0.7		0.5	39	%
Other Onshore														2.1		6.4	(66)	%
Total natural gas														21.0		32.4	(35)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM														0.7		0.9	(15)	%
West Texas		0.8		0.4	89	%		0.7		0.3	165	%		0.2		0.1	100	%
Other		0.1		0.1	(18)	%		0.1		—	(25)	%		0.2		0.4	(55)	%
Total oil and condensate		1.7		1.6	6	%		1.6		1.4	14	%
Total natural gas liquids														1.1		1.4	(22)	%

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2018		2017		%		2018		2017		%		2019		2018		%

Natural gas (million cubic feet per day)
Offshore GOM		18.6		32.0	(42)	%		22.1		32.7	(33)	%
Southeast Texas		2.9		3.7	(22)	%		3.1		3.7	(16)	%
South Texas		2.2		3.0	(29)	%		2.4		3.3	(29)	%
West Texas		0.9		0.4	142	%		0.7		0.2	282	%
Other		0.4		0.5	(16)	%		0.4		0.6	(25)	%
Total natural gas		25.0		39.6	(37)	%		28.7		40.5	(29)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM		0.6		0.9	(29)	%		0.8		0.9	(18)	%
Southeast Texas		0.3		0.3	(17)	%		0.3		0.3	(14)	%
South Texas		0.1		0.2	(38)	%		0.1		0.2	(20)	%
West Texas		0.2		0.1	125	%		0.1		0.1	213	%
Other		—		—	—	%		—		—	(100)	%
Total natural gas liquids		1.2		1.5	(18)	%		1.3		1.5	(11)	%
Total (million cubic feet equivalent per day)
Offshore GOM		23.7		39.6	(40)	%		27.8		40.0	(31)	%		23.5		32.0	(27)	%
Southeast Texas		6.4		8.2	(22)	%		6.9		8.4	(18)	%
South Texas		4.5		5.6	(19)	%		4.9		6.0	(18)	%
West Texas		6.7		3.3	99	%		5.6		2.0	181	%		5.9		4.5	33	%
Other		1.1		1.3	(13)	%		1.0		1.4	(25)	%
Other Onshore														6.5		13.5	(52)	%
Total production		42.4		58.0	(27)	%		46.2		57.8	(20)	%		35.9		50.0	(28)	%

Average Sales Price:
Oil and condensate (per barrel)	$	63.53	$	45.61	39	%	$	63.16	$	46.99	34	%	$	51.08	$	62.76	(19)	%
Natural gas (per thousand cubic feet)	$	2.57	$	3.09	(17)	%	$	2.78	$	3.04	(9)	%	$	2.98	$	2.96	1	%
Natural gas liquids (per barrel)	$	26.84	$	19.50	38	%	$	25.32	$	20.40	24	%	$	19.96	$	23.97	(17)	%
Total (per thousand cubic feet equivalent)	$	4.79	$	3.84	25	%	$	4.65	$	3.80	22	%	$	4.33	$	4.53	(4)	%

Expenses (thousands):
Operating expenses	$	6,478	$	6,329	2	%	$	13,405	$	13,162	2	%	$	5,192	$	6,927	(25)	%
Exploration expenses	$	394	$	284	39	%	$	863	$	375	130	%	$	224	$	469	(52)	%
Depreciation, depletion and amortization	$	9,498	$	12,714	(25)	%	$	19,983	$	24,485	(18)	%	$	7,556	$	10,485	(28)	%
Impairment and abandonment of oil and gas properties	$	777	$	1,401	(45)	%	$	4,104	$	1,431	187	%	$	587	$	3,327	(82)	%
General and administrative expenses	$	5,354	$	5,833	(8)	%	$	12,080	$	12,429	(3)	%	$	5,005	$	6,726	(26)	%
Gain (loss) from investment in affiliates (net of taxes)	$	(475)	$	166	(386)	%	$	232	$	1,950	(88)	%
Gain from investment in affiliates (net of taxes)													$	30	$	707	(96)	%

Selected data per Mcfe:
Operating expenses	$	1.68	$	1.20	40	%	$	1.60	$	1.26	27	%	$	1.60	$	1.54	4	%
General and administrative expenses	$	1.39	$	1.11	25	%	$	1.45	$	1.19	22	%	$	1.55	$	1.49	4	%
Depreciation, depletion and amortization	$	2.46	$	2.41	2	%	$	2.39	$	2.34	2	%	$	2.34	$	2.33	—	%

* Greater than 1,000%

~~Three months ended June 30, 2018~~

Quarter Ended March 31, 2019 Compared to ~~Three months ended June 30, 2017~~Quarter Ended March 31, 2018

Natural Gas, Oil and NGL Sales and Production

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

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We reported revenues of ~~$18.4~~$14.0 million for the ~~three months~~quarter ended ~~June 30, 2018,~~March 31, 2019, compared to revenues of ~~$20.3~~$20.4 million for the ~~three months~~quarter ended ~~June 30, 2017.~~March 31, 2018. The decrease in revenues was primarily attributable to lower natural gas production, which was primarily related ~~in large part~~ to ~~a shut in at the Dutch and Mary Rose Field due to a compressor installation, partially offset by the higher percentage in production from oil~~non-core property sales and the ~~benefit of higher~~expected year over year decline in our offshore properties, as well as lower crude oil ~~and natural gas liquids prices.~~prices during the quarter ended March 31, 2019.

Total equivalent production was ~~42.4~~35.9 Mmcfe/d for the ~~three months~~quarter ended ~~June 30, 2018,~~March 31, 2019, compared to ~~58.0~~50.0 Mmcfe/d in the prior year quarter. ~~This expected year over year~~Net natural gas production for the quarter ended March 31, 2019 was approximately 21.0 Mmcf/d, compared with approximately 32.4 Mmcf/d for the quarter ended March 31, 2018, of which approximately half of the decline was related to non-core property sales, and the remainder to normal field decline in ~~equivalent~~our offshore properties. Net oil production ~~volumes was mitigated in part by the fact that the percentage of~~decreased from approximately 1,600 barrels per day to 1,400 barrels per day, and NGL production decreased from ~~higher-value~~approximately 1,400 barrels per day to 1,100 barrels per day. The higher-unit value oil and ~~natural gas liquids~~NGL production (but lower volume equivalency than gas) increased from ~~32%~~35% to 41%. As the year progresses, that percentage should continue to increase due to our oil-weighted drilling program. The three months ended June 30, 2018 included a 4.2 Mmcfe/d decrease in production due to downtime related to an offshore compressor installation and maintenance and a 0.7 Mmcfe/d decrease in of total production due to the ~~sale~~success of our ~~Karnes County properties.~~

~~Average Sales Prices~~

~~The average~~oil-weighted West Texas drilling program. West Texas accounted for 17% of total equivalent ~~sales price realized~~production for the ~~three months~~quarter ended ~~June 30, 2018 was $4.79 per Mcfe~~March 31, 2019, as compared to ~~$3.84 per Mcfe~~9% of total equivalent production for the ~~three months~~quarter ended June 30, 2017. This increase was attributable primarily to the increase in the realized price of oil to $63.53 per barrel, compared to $45.61 per barrel for the three months ended June 30, 2017, and to the increase in the realized price of natural gas liquids to $26.84 per barrel, compared to $19.50 per barrel for the three months ended June 30, 2017. The increase in the average equivalent price also was a result of the increase in oil and liquids as a percentage of total production.

Approximately half of our second quarter revenues were derived from oil sales, especially in West Texas, which is our largest oil producing area. Our oil in West Texas is sold at prices related to Midland hub pricing, which has been and remains subject to a significant negative price differential, compared to Cushing hub West Texas Intermediate pricing. This negative pricing differential increased from an average of ($0.83) per barrel for the three months ended June 30, 2017 to an average of ($5.15) per barrel for the three months ended June 30,March 31, 2018. ~~Recently, the Midland–Cushing negative differential per barrel has substantially increased above historical levels.~~

~~Operating Expenses~~

Operating expenses for the three months ended June 30, 2018 were approximately $6.5 million, or $1.68 per Mcfe, compared to $6.3 million, or $1.20 per Mcfe, for the three months ended June 30, 2017. The table below provides additional detail of operating expenses for the three month periods:

Three Months Ended June 30,


2018

2017


(in thousands)

(per Mcfe)

(in thousands)

(per Mcfe)

Lease operating expenses

$
4,852

1.26

$
4,195

$ 0.79

Production & ad valorem taxes

836

0.22

709

0.13

Transportation & processing costs

285

0.07

1,073

0.20

Workover costs

505

0.13

352

0.08

Total operating expenses

$
6,478

1.68

$
6,329

$ 1.20

Lease operating expenses increased by 16% for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, primarily due to our new West Texas properties. The increase in the average expense per unit was due to overall lower production from other areas, primarily offshore, for the three months ended June 30, 2018.

Transportation and processing costs decreased by 73% for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, primarily due to lower offshore production and a prior period adjustment related to an offshore processing fee overcharge. In addition, primarily all of our offshore gas production is now routed through one pipeline instead of two, which has resulted in lower costs.

~~Impairment Expenses~~

Impairment expenses for the three months ended June 30, 2018 included a $0.4 million impairment of non-core onshore proved properties and a $0.4 million impairment of unproved properties. Impairment expenses for the three

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~~months ended June 30, 2017 were $1.4 million related to the partial impairment of two unused offshore platforms which were subsequently sold.~~

~~Depreciation, Depletion and Amortization~~

Depreciation, depletion and amortization for the three months ended June 30, 2018 was approximately $9.5 million, or $2.46 per Mcfe. This compares to approximately $12.7 million, or $2.41 per Mcfe, for the three months ended June 30, 2017. The lower depletion expense for the three months ended June 30, 2018 was primarily attributable to lower production.

~~General and Administrative Expenses~~

Total general and administrative expenses for the three months ended June 30, 2018 were approximately $5.4 million, compared to $5.8 million for the three months ended June 30, 2017. These expenses are primarily related to cash compensation and benefits, stock-based compensation, professional fees and office costs. General and administrative expenses included approximately $1.6 million in non-cash stock-based compensation, for both the current and prior year quarters.

~~Gain (Loss) from Affiliates~~

For the three months ended June 30, 2018 and June 30, 2017, we recorded a loss from affiliates of approximately $0.5 million, net of no tax expense, and a gain of $0.2 million, net of no tax expense, respectively, related to our investment in Exaro.

~~Six months ended June 30, 2018 Compared to Six months ended June 30, 2017~~

~~Natural Gas, Oil and NGL Sales and Production~~

We reported revenues of $38.9 million for the six months ended June 30, 2018, compared to revenues of $39.7 million for the six months ended June 30, 2017. The decrease in revenues was attributable to lower gas production, primarily from natural decline in the Dutch and Mary Rose Field and the shut in at this field due to a compressor installation, partially offset by the higher percentage in production from oil and the benefit of higher oil and natural gas liquids prices.

Total equivalent production was 46.2 Mmcfe/d for the six months ended June 30, 2018, compared to 57.8 Mmcfe/d in the prior year. This expected year over year decline in equivalent production volumes was mitigated in part by the fact that the percentage of production from higher-value oil and natural gas liquids increased from 30% to 38%. As the year progresses, that percentage should continue to increase due to our oil-weighted drilling program. The six months ended June 30, 2018 included a 2.0 Mmcfe/d decrease in production due to downtime related to an offshore compressor installation and maintenance.

~~Average Sales Prices~~

The average equivalent sales price realized for the six months ended June 30, 2018 was $4.65 per Mcfe compared to $3.80 per Mcfe for the six months ended June 30, 2017. This increase was attributable primarily to the increase in the realized price of oil to $63.16 per barrel, compared to $46.99 per barrel for the six months ended June 30, 2017, and to the increase in the realized price of natural gas liquids to $25.32 per barrel, compared to $20.40 per barrel for the six months ended June 30, 2017. The increase in the average equivalent price also was a result of the increase in oil and liquids as a percentage of total production.

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~~Almost half of our first six month revenues were derived from oil~~Average Sales Prices

The average equivalent sales especially in West Texas, which is our largest oil producing area. Our oil in West Texas is sold at prices related to Midland hub pricing, which has been and remains subject to a significant negative price ~~differential~~realized for the quarter ended March 31, 2019 was $4.33 per Mcfe compared to ~~Cushing hub West Texas Intermediate pricing.~~$4.53 per Mcfe for the quarter ended March 31, 2018. This ~~negative pricing differential increased from an average~~decrease was attributable primarily to the decrease in the realized price of ~~($0.30)~~oil to $51.08 per barrel, compared to $62.76 per barrel for the ~~six months~~quarter ended ~~June 30, 2017~~March 31, 2018, and to ~~an average~~the decrease in the realized price of ~~($2.39)~~NGLs to $19.96 per barrel, compared to $23.97 per barrel for the ~~six months~~quarter ended ~~June 30,~~March 31, 2018. ~~Recently, the Midland–Cushing negative differential per barrel has substantially increased above historical levels.~~

Operating Expenses

Operating expenses for the ~~six months~~quarter ended ~~June 30, 2018~~March 31, 2019 were approximately ~~$13.4~~$5.2 million, or $1.60 per Mcfe, compared to ~~$13.2~~$6.9 million, or ~~$1.26~~$1.54 per Mcfe, for the ~~six months~~quarter ended ~~June 30, 2017.~~March 31, 2018. The table below provides additional detail of operating expenses for the ~~six~~three month periods:


	Six Months Ended June 30,						Three Months Ended March 31,
	2018			2017			2019			2018
		(in thousands)	(per Mcfe)		(in thousands)	(per Mcfe)	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)
Lease operating expenses	$	9,896	$ 1.18	$	8,843	$ 0.85	$	3,685	$ 1.14	$	5,044	$ 1.12
Production & ad valorem taxes		1,618	0.19		1,368	0.13		386	0.12		782	0.17
Transportation & processing costs		882	0.11		2,114	0.20		695	0.21		597	0.13
Workover costs		1,009	0.12		837	0.08		426	0.13		504	0.12
Total operating expenses	$	13,405	1.60	$	13,162	$ 1.26	$	5,192	1.60	$	6,927	$ 1.54

Lease operating expenses ~~increased by 12%~~decreased from $5.0 million during the quarter ended March 31, 2018 to $3.7 million for the ~~six months~~quarter ended ~~June 30, 2018, compared to the six months ended June 30, 2017,~~March 31, 2019, primarily due to ~~our new West Texas properties. The increase in~~non-core property sales.

Production and ad valorem expenses decreased from $0.8 million during the ~~average expense per unit was due~~quarter ended March 31, 2018 to ~~overall~~$0.4 million for the quarter ended March 31, 2019 primarily as a result of lower production ~~from other areas, primarily offshore, for the six months ended June 30, 2018.~~

Transportation and processing costs decreased by 58% for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, primarily due to lower offshore production and a prior period adjustment related to an offshore processing fee overcharge. In addition, primarily all ofassociated with our ~~offshore gas production is now routed through one pipeline instead of two, which has resulted in lower costs.~~non-core property sales.

Impairment Expenses

~~Impairment expenses~~

No impairment of proved properties was recognized for the ~~six months~~quarter ended ~~June 30,~~March 31, 2019, compared to $2.3 million in non-cash proved property charges for the quarter ended March 31, 2018, ~~were $3.9~~related to the Vermilion 170 offshore property, which was subsequently sold on December 1, 2018. During the quarters ended March 31, 2019 and 2018, we recognized non-cash impairment expense of approximately $0.5 million and ~~included~~ approximately ~~$2.7~~$0.8 million, respectively, related to impairment ~~due to revised reserve estimates~~ of ~~onshore and offshore proved~~certain non-core unproved properties ~~and approximately $1.2 million impairment~~ primarily due to expiring leases of non-core onshore unproved properties. Impairment expenses for the six months ended June 30, 2017 were $1.4 million related to the impairment of two unused offshore platforms which were subsequently sold. leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the ~~six months~~quarter ended ~~June 30, 2018~~March 31, 2019 was approximately ~~$20.0~~$7.6 million, or ~~$2.39~~$2.34 per Mcfe. This compares to approximately ~~$24.5~~$10.5 million, or ~~$2.34~~$2.33 per Mcfe, for the ~~six months~~quarter ended ~~June 30, 2017.~~March 31, 2018. The lower depletion expense for the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019 was attributable primarily ~~attributable~~ to lower production.

General and Administrative Expenses

Total general and administrative expenses for the ~~six months~~quarter ended ~~June 30, 2018~~March 31, 2019 were approximately ~~$12.1~~$5.0 million, compared to ~~$12.4~~$6.7 million for the ~~six months~~quarter ended ~~June 30, 2017. These expenses are primarily related to cash compensation and benefits, stock-based compensation, professional fees and office costs. General~~March 31, 2018. The decrease in general and administrative expenses ~~included approximately $3.0~~primarily relates to $1.9 million in lower salaries and ~~$3.1 million in~~bonus payouts during the current quarter. Exclusive of non-cash stock-based compensation, general and administrative expenses for the ~~current and prior year periods, respectively.~~quarter ended March 31, 2019 were approximately $4.0 million, compared to $5.3 million for the quarter ended March 31, 2018.

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Gain (Loss) from Affiliates

For the ~~six months~~quarters ended ~~June 30,~~March 31, 2019 and March 31, 2018, ~~and June 30, 2017,~~ we recorded a gain from affiliates of approximately ~~$0.2~~$0.3 million, net of no tax expense, and a gain of ~~$2.0~~$0.7 million, net of no tax expense, respectively, related to our investment in Exaro.

Gain (Loss) from Sale of Assets

~~Gain from~~During the quarter ended March 31, 2019, we recorded a loss on sale of assets ~~for~~of $12 thousand primarily related to final closing adjustments from sales of non-core properties during 2018. During the ~~six months~~quarter ended ~~June 30,~~March 31, 2018 ~~was approximately $10.8 million, including~~we recorded a gain on sale of assets of $9.4 million, ~~gain from~~prior to final closing adjustments, related to the sale of our operated Eagle Ford Shale assets located in Karnes County, ~~Texas and a $1.4 million gain from the sale of our non-operated assets in Starr County,~~ Texas. Gain from sale of assets for the six months ended June 30, 2017 was approximately $2.5 million, which included a $2.9 million gain related to the sale of all of our assets in the Bob West North area and our operated assets in the Escobas area, both located in Southeast Texas, partially offset by a $0.4 million loss on the sale of inventory.

~~Other Income (Expense)~~

Other income for the six months ended June 30, 2018 was $0.9 million, which was primarily related to a reimbursement claim under our property and casualty insurance policy. Other expense for the six months ended June 30, 2017 was $30 thousand.

Capital Resources and Liquidity

During the ~~six months~~quarter ended ~~June 30, 2018,~~March 31, 2019, we incurred expenditures of ~~$29.0~~$2.8 million on capital projects, including ~~$24.7~~$0.9 million for the commencement of our drilling program in the Southern Delaware Basin and $0.6 million in leasehold acquisition costs in the Southern Delaware Basin. We also incurred $0.6 million for the drilling and completion of two non-operated wells targeting the Georgetown formation in our Other Onshore area. The remaining incurred expenditures are primarily related to workovers.

Our capital expenditure budget for 2019 remains at an estimated $30.3 million. The budget includes $6.8 million in leasehold and infrastructure costs and $21.6 million in drilling costs of up to four wells and completion costs of up to five wells in the Southern Delaware ~~Basin and $3.6~~Basin. The budget also includes $1.9 million in ~~leasehold acquisition~~drilling and ~~other non-drilling~~completion costs infor the ~~Southern Delaware Basin. For~~two above referenced non-operated wells. If we are able to refinance and/or replace our Credit Facility, we believe that our internally generated cash flow and proceeds from the ~~remainder~~sale of ~~2018,~~non-core assets, combined with availability under our Credit Facility will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve months. If we ~~have budgeted~~are not able to ~~drill three wells and complete two wells, after which we intend to review the amount and timing of~~refinance and/or replace our ~~remaining 2018 capital expenditure program. Our~~Credit Facility, there is substantial doubt about our ability ~~or commitment~~ to continue ~~our capital expenditure program will be determined based on our evaluation~~as a going concern. See “Pursuit of ~~well results, commodity prices (including the impact of the dramatic increase in the Midland-Cushing oil price differentials)~~Refinancing and ~~the availability of capital.~~Other Liquidity-Enhancing Alternatives”.

Cash From Operating Activities

Cash flows ~~from~~used in operating activities ~~provided~~were approximately ~~$13.3~~$0.1 million in cash for the ~~six months~~quarter ended ~~June 30, 2018~~March 31, 2019 compared to ~~$18.1~~$2.1 million provided by operating activities for the same period in ~~2017.~~2018. The table below provides additional detail of cash flows from operating activities for the ~~six months~~quarters ended ~~June 30, 2018~~March 31, 2019 and ~~2017:~~2018:


	Six Months Ended June 30,				Three Months Ended March 31,
	2018		2017		2019		2018
	(in thousands)				(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	11,902	$	14,785	$	4,525	$	6,308
Changes in operating assets and liabilities		1,361		3,324		(4,664)		(4,239)
Net cash provided by operating activities	$	13,263	$	18,109
Net cash provided by (used in) operating activities					$	(139)	$	2,069

Cash From Investing Activities

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

Net cash flows provided by investing activities were ~~comprised of capital expenditures net of~~$4.7 million for the quarter ended March 31, 2018, as proceeds from asset sales ~~were $8.5 million for the six months ended June 30, 2018.~~exceeded cash capital costs. We expended ~~$30.1~~$16.2 million in cash capital costs, primarily related to drilling and/or completing wells in the Southern Delaware Basin and acquiring or extending unproved leases during the ~~six months ended June 30, 2018, partially~~quarter, offset by ~~$21.6~~$21.0 million provided by the sale of our properties in Karnes County, ~~Texas and non-operated properties in Starr County,~~ Texas. Cash flows used in investing activities for the six months ended June 30, 2017 were $34.9 million, substantially all of which was used for capital expenditures related to drilling and/or completing wells in the Southern Delaware Basin and acquiring or extending unproved leases.

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Cash From Financing Activities

Cash flows provided by financing activities for the quarter ended March 31, 2019 were approximately $5.3 million, primarily related to net borrowings outstanding under our Credit Facility. Cash flows used in financing activities for the ~~six months~~quarter ended ~~June 30,~~March 31, 2018 were approximately ~~$4.7~~$6.8 million, primarily related to net repayment of borrowings outstanding under our ~~credit facility. Cash flows provided by financing activities for the six months ended June 30, 2017 were approximately $16.8 million, primarily related to net borrowings under our credit facility.~~Credit Facility.

~~RBC~~ Credit Facility

~~In October 2013, we entered into a four-year~~Our $500 million secured revolving credit facility with Royal Bank of Canada and other lenders ~~(“RBC Credit~~(the “Credit Facility”), ~~the maturity of which has been extended by subsequent amendment to~~currently matures October 1, 2019. The borrowing base under the facility is redetermined each November and May. As of ~~June 30, 2018,~~March 31, 2019, the borrowing base under the ~~RBC~~ Credit Facility was ~~$110~~$90 million, ~~but was reduced~~with $22.6 million available for borrowings. We are currently going through our regularly scheduled May redetermination process. Our redetermination process may result in a reaffirmation of the borrowing base or a material reduction in the borrowing base. Any reduction would further reduce our access to ~~$105 million effective August 1, 2018, as agreed~~capital to ~~during the May 2018 redeterminations.~~finance operations and growth. Amounts borrowed in excess of any lowered borrowing base would be due and payable within a six month period.

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 June 30, 2018, we were in compliance with all but the Current Ratio covenant under the RBC Credit Facility, although we obtained a waiver for such non-compliance effective for June 30, 2018.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 March 31, 2019, we were in compliance with all of our covenants under the Credit Facility.

Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives

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

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

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our ~~2017~~2018 Form 10-K.

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Recent Accounting Pronouncements

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

Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of ~~June 30, 2018, the primary off-balance sheet arrangements that~~March 31, 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 2017 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.

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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 six months ended June 30, 2018,As a ~~10% fluctuation in the prices received for natural gas and oil production would have had an approximate $1.8 million and $3.9 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 our current derivative contracts are large financial institutions and also lenders or affiliates of lenders in our 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 June 30, 2018, 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.

~~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 June 30, 2018, our total long-term debt was $80.8 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 six months ended June 30, 2018, our effective rates fluctuated between 4.9% and 8.0%, depending on the term of the specific debt drawdowns. At June 30, 2018, we did not have any outstanding interest rate swap agreements. As of June 30, 2018, the weighted average interest rate on our variable rate debt was 5.75% per year.

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~~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 expense~~information required by ~~$0.4 million for the six month period.~~this Item.

~~Other Financial Instruments~~

As of June 30, 2018, 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 June 30, 2018, an immediate 10% change in interest rates would result in a $0.5 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 and 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 ~~June 30, 2018.~~March 31, 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 ~~June 30, 2018,~~March 31, 2019, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer and our Chief Financial and Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the ~~three months~~quarter ended ~~June 30, 2018~~March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. However, the adoption of Accounting Standard Codification 606, Revenue from Contracts with Customers (“ASC 606”) in January 2018, did require the implementation of new accounting processes during the three months ended June 30, 2018, which changed the Company's internal controls relating to revenue by reviewing new contracts or modifications to existing contracts, as well as any significant increase in sales level on a quarterly basis to monitor the significance of ASC 606 going forward.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 1112 to our Financial Statements – “Commitments and Contingencies.”

Item 1A. Risk Factors

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, ~~2017 and in Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31,~~ 2018.

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

The Company ~~repurchased~~withheld the following shares from employees during the ~~three months~~quarter ended ~~June 30, 2018~~March 31, 2019 for the payment of ~~withholding~~ 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 Paid

Purchased as Part of

of Shares that may yet

Period

Shares Purchased

Per Share

Publicly Announced Program


be Purchased Under Program

April 2018

32,288

$
3.69

—

$
—

May 2018

1,271

$
3.77

—

$
—

June 2018

144

$
4.93

—

$
—

Total

33,703

$
3.70

—

$
31.8 million



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

January 2019	-	$	-	—	$	—
February 2019	39,490	$	3.85	—	$	—
March 2019	9,925	$	3.43	—	$	—
Total	49,415	$	3.77	—	$	31.8 million (1)

(1)

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

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

~~Tax Benefit Preservation Plan~~

On August 1, 2018, the Board of Directors (the “Board”) of Contango declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend will be issued to the stockholders of record at the close of business on August 13, 2018, the Record Date. Each Right entitles the registered holder, subject to the terms of the Rights Agreement (as defined below), to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock, $0.04 par value per share (the “Preferred Stock”), of the Company, at a price of $33.72, subject to certain adjustments. The description and terms of the Rights are set forth in the Rights Agreement dated as of August 1, 2018 (the “Rights Agreement”) between the Company and Continental Stock Transfer & Trust Company, as Rights Agent. A copy of the Rights Agreement has been filed with the SEC as an exhibit to a Current Report on Form 8-K filed on August 2, 2018.

In connection with the adoption of the Rights Agreement, the Board adopted a Certificate of Designations of the Preferred Stock. The Certificate of Designations was filed with the Secretary of State of the State of Delaware and became effective on August 1, 2018.

The purpose of the Rights Agreement is to diminish the risk that the Company’s ability to use its net operating losses and certain other tax assets to reduce potential future federal income tax obligations would become subject to limitations by reason of the Company’s experiencing an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Tax Code”). A company generally experiences such an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by (i) discouraging any person or group from becoming a 4.95% shareholder and (ii) discouraging any existing 4.95% shareholder from acquiring additional shares of the Company’s common stock.None.

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Item 6. Exhibits

Exhibit Number		Description
3.1		Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000 and incorporated by reference herein).
3.2		Amendment to the Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Quarterly Report on Form 10-QSB for the quarter ended September 30, 2002, as filed with the Securities and Exchange Commission on November 14, 2002 and incorporated by reference herein).
3.3		Third Amended and Restated Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on March 3, 2015 and incorporated by reference herein).
3.4		Certificate of Designations of Series A Junior Participating Preferred Stock of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s ~~Current~~ Report on Form 8-K dated August 1, 2018, as filed with the Securities and Exchange Commission on August 2, 2018 and incorporated by reference herein).
~~4.1~~3.5		~~Rights Agreement, dated as~~Certificate of ~~August 1, 2018, between~~Elimination of Series A Junior Participating Preferred Stock of Contango Oil & Gas Company, as filed with the ~~Company, and Continental Stock Transfer & Trust Company, as Rights Agent~~Secretary of the State of Delaware on March 14, 2019 (filed as Exhibit ~~4.1~~3.5 to the Company’s ~~Current~~ Report on Form ~~8-K dated August 1,~~10-K for the fiscal year ended December 31, 2018, as filed with the Securities and Exchange Commission on ~~August 2, 2018,~~March 18, 2019 and incorporated by reference ~~herein)~~herein).
10.1		~~Fifth Amendment to Credit~~Separation Agreement ~~among~~and General Release by Contango Oil & Gas Company and Jay S. Mengle dated March 25, 2019 (filed as ~~Borrower, Royal Bank of Canada,~~Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 25, 2019, as ~~Administrative Agent,~~filed with the Securities and ~~the Lenders signatory thereto. †~~Exchange Commission on March 26, 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: ~~August~~May 8, ~~2018~~2019	By:	/s/ ~~ALLAN D. KEEL~~WILKIE S. COLYER
		~~Allan D. Keel~~Wilkie S. Colyer
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: ~~August~~May 8, ~~2018~~2019	By:	/s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

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	June 30, 2018		December 31, 2017
Current assets (1)	$	12,910	$	17,063
Non-current assets:
Net property and equipment		77,837		82,450
Gas processing deposit		1,150		1,150
Other non-current assets		445		390
Total non-current assets		79,432		83,990
Total assets	$	92,342	$	101,053

Current liabilities	$	4,415	$	6,199
Non-current liabilities:
Long-term debt		32,411		40,375
Other non-current liabilities		3,958		3,858
Total non-current liabilities		36,369		44,233
Members' equity		51,558		50,621
Total liabilities & members' equity	$	92,342	$	101,053


	Three Months Ended
	June 30, 2017	September 30, 2017	December 31, 2017	March 31, 2018	June 30, 2018
Offshore GOM
Dutch and Mary Rose (1)	36.3	32.2	30.8	29.0	21.0
Vermilion 170 (2)	3.1	4.2	3.5	3.0	2.7
South Timbalier 17 (3)	0.2	0.1	—	—	—
Southeast Texas (4)	8.2	7.8	7.5	7.3	6.4
South Texas (5)	5.6	4.6	5.8	5.3	4.5
West Texas	3.3	3.2	3.2	4.5	6.7
Other (6)	1.3	1.1	1.0	0.9	1.1
	58.0	53.2	51.8	50.0	42.4