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, 2019~~March 31, 2020


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

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

TEXAS		95-4079863

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

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

(713) 236-7400

(Registrant’s telephone number, including area code)

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

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

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

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

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


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

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

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

The total number of shares of common stock, par value $0.04 per share, outstanding as of ~~August 5, 2019~~June 17, 2020 was ~~34,434,406~~.131,689,480.

Table of Contents

Explanatory Note

On March 25, 2020, the U.S. Securities and Exchange Commission issued an order under Section 36 (Release No. 34-88465) of the Securities Exchange Act of 1934 (the “Exchange Act”) granting exemptions from specified provisions of the Exchange Act and certain rules thereunder (the “Order”). The Order provides conditional relief to public companies that are unable to timely comply with their filing obligations as a result of the novel coronavirus (“COVID-19”) pandemic. Contango Oil & Gas Company (the “Company”) relied on the Order to delay the filing of this Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, due to circumstances related to COVID-19. The Company’s headquarters and other accounting offices are located in areas of the United States that have been under “lock-down” or “stay at home” orders implemented in response to the COVID-19 pandemic. The Company’s accounting personnel have been working remotely since the orders were implemented and have also been operating under travel and work restrictions stemming from the COVID-19 pandemic. As a result, the Company’s accounting workflow and its ability to complete necessary review processes and procedures with respect to its financial statements were negatively impacted. Accordingly, the Company required additional time to prepare and finalize this report.

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE ~~SIX~~THREE MONTHS ENDED ~~JUNE 30, 2019~~MARCH 31, 2020

TABLE OF CONTENTS



			Page
				~~Page~~	PART I—FINANCIAL INFORMATION
~~PART I—FINANCIAL INFORMATION~~

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019	3	4
	Consolidated Statements of Operations (unaudited) for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	4	5
	Consolidated Statements of Cash Flows (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	5	6
	Consolidated Statement of Shareholders’ Equity (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	6	7
	Notes to the Consolidated Financial Statements (unaudited)	8	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	35

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults upon Senior Securities	37
Item 4.	Mine Safety Disclosures	38	37
Item 5.	Other Information	38	37
Item 6.	Exhibits	38

~~All~~Unless the context requires otherwise or unless otherwise noted, 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.

Table of Contents

Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)


	June 30,		December 31,
	2019		2018

	(unaudited)

					March 31,		December 31,
					2020		2019

					(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	1,685	$	1,624
Accounts receivable, net		10,147		11,531		28,565		39,567
Prepaid expenses		1,005		1,303		1,436		1,191
Current derivative asset		2,149		4,600		30,980		3,819
Other current assets		391		—
Inventory						187		150
Deposits and other						7,106		36
Total current assets		13,692		17,434		69,959		46,387
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		1,098,773		1,095,417		1,314,886		1,306,916
Unproved properties		44,003		34,612		24,002		27,619
Other property and equipment		1,331		1,314		1,629		1,655
Accumulated depreciation, depletion and amortization		(912,347)		(898,169)		(1,202,643)		(1,045,070)
Total property, plant and equipment, net		231,760		233,174		137,874		291,120
OTHER NON-CURRENT ASSETS:
Investments in affiliates		6,480		5,743		7,052		6,766
Long-term derivative asset		244		—		9,474		357
Deferred tax asset		—		424
Other non-current assets		480		357
Right-of-use lease assets						5,305		5,885
Debt issuances costs						3,135		3,311
Total other non-current assets		7,204		6,524		24,966		16,319
TOTAL ASSETS	$	252,656	$	257,132	$	232,799	$	353,826


CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	47,966	$	39,506	$	83,742	$	104,593
Current derivative liability		292		422		534		3,951
Current asset retirement obligations		826		1,329		1,677		2,003
Current portion of long-term debt		60,000		60,000
Total current liabilities		109,084		101,257		85,953		110,547
NON-CURRENT LIABILITIES:
Long-term debt		—		—		82,768		72,768
Long-term derivative liability						325		2,020
Asset retirement obligations		11,725		12,168		50,626		49,662
Other long-term liabilities		3,677		3,318
Lease liabilities						2,196		2,789
Total non-current liabilities		15,402		15,486		135,915		127,239
Total liabilities		124,486		116,743
COMMITMENTS AND CONTINGENCIES (NOTE 12)
TOTAL LIABILITIES						221,868		237,786
COMMITMENTS AND CONTINGENCIES (NOTE 11)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 100 million shares authorized, 39,967,341 shares issued and 34,442,843 shares outstanding at June 30, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018		1,587		1,573
Series C contingent convertible preferred stock, $0.04 par value, 2,700,000 shares authorized, issued and outstanding at March 31, 2020 and December 31, 2019						108		108
Common stock, $0.04 par value, 200 million shares authorized, 129,062,631 shares issued and 129,005,827 shares outstanding at March 31, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019						5,151		5,148
Additional paid-in capital		341,563		339,981		472,078		471,778
Treasury shares at cost (5,524,498 shares at June 30, 2019 and 5,458,950 shares at December 31, 2018)		(129,266)		(129,030)
Retained deficit		(85,714)		(72,135)
Treasury shares at cost (56,804 shares at March 31, 2020 and 7,330 shares at December 31, 2019)						(175)		(18)
Accumulated deficit						(466,231)		(360,976)
Total shareholders’ equity		128,170		140,389		10,931		116,040
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	252,656	$	257,132	$	232,799	$	353,826

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(unaudited)				(unaudited)

									Three Months Ended
									March 31,
									2020		2019
									(unaudited)
REVENUES:
Oil and condensate sales	$	7,439	$	9,607	$	13,845	$	18,418	$	22,782	$	6,406
Natural gas sales		3,857		5,848		9,499		14,457		8,170		5,642
Natural gas liquids sales		1,466		2,993		3,429		6,010		3,621		1,963
Total revenues		12,762		18,448		26,773		38,885		34,573		14,011
EXPENSES:
Operating expenses		5,694		6,478		10,886		13,405		21,483		5,192
Exploration expenses		249		394		473		863		398		224
Depreciation, depletion and amortization		7,573		9,498		15,129		19,983		12,854		7,556
Impairment and abandonment of oil and gas properties		1,247		777		1,834		4,104		145,878		587
General and administrative expenses		4,456		5,354		9,461		12,080		5,425		5,005
Total expenses		19,219		22,501		37,783		50,435		186,038		18,564
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates, net of income taxes		427		(475)		457		232
Gain from sale of assets		421		1,370		409		10,817
Gain from investment in affiliates, net of income taxes										286		30
Gain (loss) from sale of assets										27		(12)
Interest expense		(1,079)		(1,262)		(2,171)		(2,671)		(1,213)		(1,092)
Gain (loss) on derivatives, net		2,065		(2,610)		(813)		(3,642)		46,699		(2,878)
Other income		89		3		3		882
Other income (expense)										805		(86)
Total other income (expense)		1,923		(2,974)		(2,115)		5,618		46,604		(4,038)
NET LOSS BEFORE INCOME TAXES		(4,534)		(7,027)		(13,125)		(5,932)		(104,861)		(8,591)
Income tax provision		(427)		(151)		(454)		(309)
Income tax benefit (provision)										(394)		(27)
NET LOSS	$	(4,961)	$	(7,178)	$	(13,579)	$	(6,241)	$	(105,255)	$	(8,618)
NET LOSS PER SHARE:
Basic	$	(0.15)	$	(0.29)	$	(0.40)	$	(0.25)	$	(0.80)	$	(0.26)
Diluted	$	(0.15)	$	(0.29)	$	(0.40)	$	(0.25)	$	(0.80)	$	(0.26)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		33,909		24,933		33,840		24,863		131,338		33,770
Diluted		33,909		24,933		33,840		24,863		131,338		33,770

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Six Months Ended
	June 30,
	2019		2018

	(unaudited)

					Three Months Ended
					March 31,
					2020		2019

					(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(13,579)	$	(6,241)	$	(105,255)	$	(8,618)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		15,129		19,983		12,854		7,556
Impairment of natural gas and oil properties		1,079		3,890		145,878		483
Amortization of debt issuance costs						177		—
Deferred income taxes		424		—		—		424
Gain on sale of assets		(409)		(10,817)
Loss (gain) on sale of assets						(27)		12
Gain from investment in affiliates		(457)		(232)		(286)		(30)
Stock-based compensation		1,637		3,008		350		1,052
Unrealized loss on derivative instruments		2,078		2,311
Unrealized loss (gain) on derivative instruments						(41,391)		3,646
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables		1,530		2,132		10,761		146
Decrease in prepaids		298		352
Increase (decrease) in accounts payable & advances from joint owners		8,592		(2,027)
Decrease (increase) in prepaids						(245)		835
Increase in inventory						(1)		—
Decrease in accounts payable & advances from joint owners						(14,326)		(4,299)
Decrease in other accrued liabilities		(350)		(2,618)		(1,951)		(826)
Increase in income taxes receivable, net		(424)		—
Increase (decrease) in income taxes payable, net		(258)		229
Other		(392)		3,293
Net cash provided by operating activities	$	14,898	$	13,263
Decrease (increase) in income taxes receivable, net						241		(424)
Increase in income taxes payable, net						192		27
Increase in deposits and other						(7,219)		(123)
Net cash used in operating activities					$	(248)	$	(139)
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	$	(14,604)	$	(30,077)	$	(9,492)	$	(5,124)
Additions to furniture & equipment		(17)		—		—		(17)
Sale of oil & gas properties		—		21,562		5		—
Net cash used in investing activities	$	(14,621)	$	(8,515)	$	(9,487)	$	(5,141)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	73,548	$	130,677	$	37,000	$	37,025
Repayments under credit facility		(73,548)		(135,230)		(27,000)		(31,473)
Net costs from equity offering		(41)		—		(47)		(86)
Purchase of treasury stock		(236)		(195)		(157)		(186)
Net cash used in financing activities	$	(277)	$	(4,748)
Net cash provided by financing activities					$	9,796	$	5,280
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	—	$	—	$	61	$	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—		—		1,624		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—	$	—	$	1,685	$	—

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020

(in thousands, except number of shares)


				Additional						Total
	Common Stock			Paid-in		Treasury		Retained		Shareholders’
	Shares	Amount		Capital		Stock		Deficit		Equity
	(unaudited)
Balance at December 31, 2018	34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389

												Series C						Additional						Total
												Preferred Stock			Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
												Shares	Amount		Shares	Amount		Capital		Stock		Deficit		Equity
															(unaudited)
Balance at December 31, 2019												2,700,000	$	108	128,977,816	$	5,148	$	471,778	$	(18)	$	(360,976)	$	116,040
Equity offering costs	—		—		(86)		—		—		(86)	—		—	—		—		(47)		—		—		(47)
Treasury shares at cost	(49,415)		—		—		(186)		—		(186)	—		—	(49,474)		—		—		(157)		—		(157)
Restricted shares activity	307,650		12		(12)		—		—		—	—		—	77,485		3		(3)		—		—		—
Stock-based compensation	—		—		1,052		—		—		1,052	—		—	—		—		350		—		—		350
Net loss	—		—		—		—		(8,618)		(8,618)	—		—	—		—		—		—		(105,255)		(105,255)
Balance at March 31, 2019	34,416,727	$	1,585	$	340,935	$	(129,216)	$	(80,753)	$	132,551
Equity offering costs	—		—		45		—		—		45
Treasury shares at cost	(16,133)		—		—		(50)		—		(50)
Restricted shares activity	42,249		2		(2)		—		—		—
Stock-based compensation	—		—		585		—		—		585
Net loss	—		—		—		—		(4,961)		(4,961)
Balance at June 30, 2019	34,442,843	$	1,587	$	341,563	$	(129,266)	$	(85,714)	$	128,170
Balance at March 31, 2020												2,700,000	$	108	129,005,827	$	5,151	$	472,078	$	(175)	$	(466,231)	$	10,931

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019

(in thousands, except number of shares)


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

															Additional						Total
												Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
												Shares	Amount		Capital		Stock		Deficit		Equity
												(unaudited)
Balance at December 31, 2018												34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering costs												—		—		(86)		—		—		(86)
Treasury shares at cost	(33,703)		—		—		(124)		—		(124)	(49,415)		—		—		(186)		—		(186)
Restricted shares activity	77,188		4		(4)		—		—		—	307,650		12		(12)		—		—		—
Stock-based compensation	—		—		1,584		—		—		1,584	—		—		1,052		—		—		1,052
Net loss	—		—		—		—		(7,178)		(7,178)	—		—		—		—		(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

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.~~company, with regional offices in Oklahoma City and Stillwater, Oklahoma. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas, Oklahoma, Louisiana 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~~across the United States. On June 14, 2019, following approval by the Company’s stockholders at the 2019 annual meeting of stockholders, the Company changed its state of incorporation from the State of Delaware to the State of Texas and increased the Company’s number of authorized shares of common stock from 50 million to 100 million.

The following table lists the Company’s primary producing areas as of ~~June 30, 2019:~~March 31, 2020:

Location		Formation
Gulf of Mexico		Offshore Louisiana - water depths less than 300 feet
Mid-continent Region of Oklahoma		Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork
Southern Delaware Basin, Pecos County, Texas		Wolfcamp A and B
Madison and Grimes counties, Texas		Woodbine ~~(Upper Lewisville)~~/ Upper Lewisville
Zavala and Dimmit counties, Texas		Buda / Eagle Ford / Georgetown
San Augustine County, Texas		Haynesville shale, Mid Bossier shale and James Lime ~~formations~~
Other Texas Gulf Coast		Conventional and smaller unconventional formations
Weston County, Wyoming		Muddy Sandstone
Sublette County, Wyoming		Jonah Field ⁽¹⁾

(1)

~~(1)~~

Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in the Company’s reported production results for all periods shown in this report.

~~Since~~From the Company’s initial entry into the Southern Delaware Basin in 2016 and through mid-2019, the Company ~~has been~~was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. In January 2020, the Company brought one West Texas~~, which is expected to continue to generate positive returns~~ well online but suspended further drilling in the ~~current price environment.~~area in response to the dramatic decline in oil prices during the quarter. As of ~~June 30, 2019,~~March 31, 2020, the Company was producing from ~~twelve~~eighteen wells over its approximate ~~17,000~~17,200 gross operated ~~(8,100 total~~(8,000 company net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

~~The~~During the fourth quarter of 2019, the Company ~~currently expects this~~closed on the acquisitions of certain producing assets and undeveloped acreage ~~in West Texas to be the primary focus~~of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its ~~drilling program~~affiliates (collectively, “White Star”) and established an additional core strategic area, primarily located in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative, as production from these acquisitions represented 74% of the Company’s total net production for the ~~remainder~~first quarter of ~~2019. Until a sustained improvement in commodity prices occurs,~~2020.

During the fourth quarter of 2019, the Company also entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline. The Iron Flea prospect was spud in late May 2020. On June 12, 2020, the target drilling depth was reached, and the prospect was determined unsuccessful. No further evaluation of that prospect is anticipated. As of March 31, 2020, the Company paid approximately $7.2 million in costs associated with the drilling of the Iron Flea prospect, of which $7.1 million was escrowed for the benefit of the turnkey drilling and is currently included in the Company’s consolidated balance sheet in “Deposits and other”. These costs will ~~commit drilling capital~~be expensed as exploration expense in the second quarter of 2020.

Impact of the COVID-19 Pandemic

A novel strain of the coronavirus ("COVID-19") surfaced in late 2019 and has spread around the world, including to ~~West Texas,~~the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other ~~areas, only~~restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to ~~fulfill leasehold commitments, preserve core acreage~~the

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battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and ~~where determined appropriate~~other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to ~~do so, expand its presence~~global oil demand, which is negatively impacting the Company's results of operations and planned 2020 capital activities. Due to the extreme volatility in those existing areas. The Company will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales. During this time,oil prices, the Company ~~will continue to identify opportunities~~has suspended any further plans for ~~cost reductions and operating efficiencies~~onshore drilling in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves.2020.

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (“~~2018~~2019 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the ~~2018~~2019 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report.

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Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the ~~2018~~2019 Form 10-K. These unaudited interim consolidated results of operations for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 are not necessarily indicative of the results that may be expected for the full year ending December 31, ~~2019.~~2020.

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

~~Liquidity and Going Concern~~

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

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed, whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment of Long-Lived Assets

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices,

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operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to,

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estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. ~~During~~

In the ~~six~~first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas in March 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the three months ended ~~June 30, 2019,~~March 31, 2020, the Company ~~recognized $0.2~~recorded a $143.3 million in non-cash charge for proved property impairment of its onshore properties related to ~~leases~~the dramatic decline in ~~Wyoming~~commodity prices, as discussed above, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and ~~an onshore non-operated property~~the associated change in ~~an area previously impaired due to revised reserve estimates made~~its current development plans for its proved, undeveloped locations. No impairment of proved properties was recorded during the ~~quarter ended December 31, 2018. During the six~~three months ended June 30, 2018, the Company recognized $2.7 million in non-cash proved property impairment charges, $2.3 million of which related to its Vermilion 170 offshore property and $0.4 million of which related to non-core onshore properties due to revised reserve estimates. The Vermilion 170 offshore property was subsequently sold effective December 1, 2018March 31, 2019.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company ~~recognized~~recorded a $2.6 million non-cash charge for unproved impairment expense during the three months ended March 31, 2020. The impairment primarily related to acquired leases in the Company’s Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which the Company has no current plans to develop as a result of the current commodity price environment. During the three months ended March 31, 2019, the Company recorded non-cash impairment expense of ~~approximately $0.4~~$0.5 million ~~and approximately $0.9 million for three and six months ended June 30, 2019, respectively,~~ related to impairment of certain unproved properties, primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.4 million and approximately $1.2 million for three and six months ended June 30, 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.

Net Loss Per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. ~~For the three and six months ended June 30, 2019, the~~The Company excluded ~~648,170~~366,749 shares or units and ~~561,164~~526,309 shares or units ~~respectively,~~ of potentially dilutive securities ~~as they were antidilutive. For~~during each of the three ~~and six~~ months ended ~~June 30, 2018, the Company excluded 1,628,321 shares or units~~March 31, 2020 and ~~1,713,673 shares or units,~~2019, respectively, ~~of potentially dilutive securities,~~ as they were antidilutive.

Subsidiary Guarantees

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

Revenue Recognition

~~Adoption of ASC 606~~

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

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

~~Revenue from Contracts with Customers~~

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

Table of ~~the transaction price allocated to remaining performance obligation is not required.~~Contents

~~Contract Balances~~

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

~~Prior Period Performance Obligations~~

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

~~Impact of Adoption of ASC 606~~

The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the six months ended June 30, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of

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~~gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the~~ Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Leases

The Company recognizes 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. The Company does 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. The Company has modified procedures to its existing internal controls to review any new contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease at inception. The Company will continue to review all new or modified contracts on a quarterly basis for proper treatment. See Note 6 - "Leases" for additional information.

Recent Accounting Pronouncements

In ~~August 2018,~~June 2016, the FASB issued ASU ~~2018-13~~2016-13 – ~~Fair Value~~Financial Instruments – Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments – Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU 2019-05 (“ASU 2019-05”): Financial Instruments-Credit Losses (Topic 326) – Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 – Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic ~~820”~~740”).: Simplifying the Accounting for Income Taxes. The amendments in ASU ~~2018-13 modify~~2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the ~~disclosure requirements on fair value measurements in~~accounting for income taxes by removing certain exceptions from Topic ~~820.~~740 and making minor improvements to the codification. The amendments in this update are effective for ~~all~~public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, ~~2019.~~2020. 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~~

OnIn March ~~28, 2018,~~2020, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.4 million, prior to final closing adjustments.

~~On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a gain of $1.4 million after removal~~FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the ~~asset retirement obligations associated with~~Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. ASU 2020-04 will be in effect through December 31, 2022. We are currently assessing the ~~sold properties.~~potential impact of ASU 2020-04 on our consolidated financial statements.

~~On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption~~12

Table of ~~the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million after removal of the asset retirement obligations associated with the sold properties.~~Contents

4.3. Fair Value Measurements

~~Pursuant to Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures (“ASC 820”), the~~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~~Fair value asis 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~~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, 2019. As required by ASC 820, a~~March 31, 2020. 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, 2019~~March 31, 2020 (in thousands):


	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3

									Total		Fair Value Measurements Using
									Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	2,393	$	—	$	2,393	$	—	$	40,454	$	—	$	40,454	$	—
Commodity price contracts - liabilities	$	(292)	$	—	$	(292)	$	—	$	(859)	$	—	$	(859)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative ~~asset”~~asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The

Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in its consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note ~~5 -~~4 – "Derivative Instruments" for additional discussion of derivatives.

As of ~~June 30, 2019,~~March 31, 2020, the Company's derivative contracts were all with major institutions with investment grade credit ratings which are believed to have minimal credit ~~risk.~~risk, which primarily are lenders within the Company’s bank group. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Estimates of the fair value of financial instruments ~~are made in accordance with the requirements of Accounting Standards Codification Topic 825, Financial Instruments. The estimated fair value amounts~~ are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Credit ~~Facility~~Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note ~~10 - "Indebtedness"~~9 – “Long-Term Debt” for further information.

Impairments

The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital

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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.

5.4. Derivative Instruments

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

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As of ~~June 30, 2019,~~March 31, 2020, the Company’s natural gas and oil derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for ~~crude~~ oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit ~~Facility~~Agreement (as defined below) or under unsecured lines of credit with non-bank counterparties. See Note 109 – ~~“Indebtedness”~~“Long-Term Debt” for further information regarding the Credit ~~Facility.~~Agreement.

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

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As of ~~June 30, 2019,~~March 31, 2020, the following financial derivative instruments were in place (fair value in thousands):

Commodity

Period

Derivative

Volume/Month

Price/Unit

Fair Value

Natural Gas

July 2019

Swap

600,000
Mmbtus

$
2.75
(1)

$
278

Natural Gas

Aug 2019 - Oct 2019

Swap

100,000
Mmbtus

$
2.75
(1)

$
136

Natural Gas

Nov 2019 - Dec 2019

Swap

500,000
Mmbtus

$
2.75
(1)

$
267

Oil

July 2019 - Dec 2019

Collar

7,000
Bbls

$
50.00
-
58.00
(2)

$
(237)

Oil

July 2019 - Dec 2019

Collar

4,000
Bbls

$
52.00
-
59.45
(3)

$
(33)

Oil

July 2019

Swap

6,000
Bbls

$
66.10
(3)

$
46

Oil

July 2019

Swap

12,000
Bbls

$
72.10
(3)

$
163

Oil

Aug 2019 - Oct 2019

Swap

9,000
Bbls

$
72.10
(3)

$
370

Oil

Nov 2019 - Dec 2019

Swap

12,000
Bbls

$
72.10
(3)

$
340

Oil

July 2019 - Dec 2019

Swap

2,400
Bbls

$
61.72
(3)

$
51

Natural Gas

Jan 2020 - March 2020

Swap

425,000
Mmbtus

$
2.84
(1)

$
225

Natural Gas

April 2020 - July 2020

Swap

400,000
Mmbtus

$
2.53
(1)

$
167

Natural Gas

Aug 2020 - Oct 2020

Swap

40,000
Mmbtus

$
2.53
(1)

$
5

Natural Gas

Nov 2020 - Dec 2020

Swap

375,000
Mmbtus

$
2.70
(1)

$
38

Oil

Jan 2020 - June 2020

Swap

22,000
Bbls

$
57.74
(3)

$
148

Oil

July 2020 - Dec 2020

Swap

15,000
Bbls

$
57.74
(3)

$
221

Total net fair value of derivative instruments

$
2,185



Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532			⁽¹⁾	$	1,271
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.532			⁽¹⁾	$	62

Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.696			⁽¹⁾	$	180

Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.53			⁽¹⁾	$	1,268
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.53			⁽¹⁾	$	587

Natural Gas	April 2020 - July 2020	Swap	400,000	Mmbtus	$	2.532			⁽¹⁾	$	1,271
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.532			⁽¹⁾	$	591

Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.505			⁽¹⁾	$	(98)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.505			⁽¹⁾	$	66
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.505			⁽¹⁾	$	2

Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.508			⁽¹⁾	$	(96)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.508			⁽¹⁾	$	67
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.508			⁽¹⁾	$	2

Natural Gas	Jan 2021 - March 2021	Swap	650,000	Mmbtus	$	2.508			⁽¹⁾	$	(340)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	Mmbtus	$	2.508			⁽¹⁾	$	348
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	Mmbtus	$	2.508			⁽¹⁾	$	(36)

Natural Gas	April 2021 - Nov 2021	Swap	70,000	Mmbtus	$	2.36			⁽¹⁾	$	(87)
Natural Gas	Dec 2021	Swap	350,000	Mmbtus	$	2.36			⁽¹⁾	$	(21)

Natural Gas	Jan 2022 - March 2022	Swap	780,000	Mmbtus	$	2.542			⁽¹⁾	$	(216)

Oil	April 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00	-	65.70	⁽²⁾	$	559

Oil	April 2020 - June 2020	Swap	22,000	Bbls	$	57.74			⁽²⁾	$	2,139
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			⁽²⁾	$	2,257

Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33			⁽²⁾	$	218
Oil	July 2020	Swap	5,500	Bbls	$	54.33			⁽²⁾	$	132
Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33			⁽²⁾	$	164
Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33			⁽²⁾	$	141

Oil	April 2020 - July 2020	Swap	37,500	Bbls	$	54.70			⁽²⁾	$	4,217
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70			⁽²⁾	$	3,780

Oil	April 2020 - July 2020	Swap	37,500	Bbls	$	54.58			⁽²⁾	$	4,199
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58			⁽²⁾	$	3,759

Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00			⁽²⁾	$	837
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00			⁽²⁾	$	647
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00			⁽²⁾	$	252

Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00			⁽²⁾	$	6,936
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00			⁽²⁾	$	1,610
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00			⁽²⁾	$	2,682

		Total net fair value of derivative instruments								$	39,350

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

(2) Based on ~~Argus Louisiana Light Sweet crude~~West Texas Intermediate oil prices.

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

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI -– Cushing 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~~April 2020 through June 2020 and 10,000

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barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in ~~a liability~~an asset position of ~~$84 thousand~~$0.2 million as of ~~June 30, 2019.~~March 31, 2020.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of ~~June 30, 2019~~March 31, 2020 (in thousands):


	Gross		Netting (1)		Total

							Gross		Netting ⁽¹⁾		Total
Assets	$	2,393	$	—	$	2,393	$	40,454	$	—	$	40,454
Liabilities	$	(292)	$	—	$	(292)	$	(859)	$	—	$	(859)

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

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


	Gross		Netting (1)		Total

							Gross		Netting ⁽¹⁾		Total
Assets	$	4,600	$	—	$	4,600	$	4,176	$	—	$	4,176
Liabilities	$	(422)	$	—	$	(422)	$	(5,971)	$	—	$	(5,971)

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approximately ~~$1.4~~$1.0 million in restricted stock compensation expense during the ~~six~~three months ended ~~June 30,~~March 31, 2019 related to restricted stock granted to its officers, employees and directors. As of June 30, 2019, an additional $1.6 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.8 years. Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of June 30, 2019, assuming PSUs (as defined below) are settled at 100% of target.

During the six months ended June 30, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. Additionally, during the

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six months ended June 30, 2018, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2018, was $3.76 per share, with a total fair value of approximately $1.2 million and no adjustment for an estimated weighted average forfeiture rate. During the six months ended June 30, 2018, 24,980 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2018 was approximately $0.2 million. The Company recognized approximately $1.8 million in restricted stock compensation expense during the six months ended June 30, 2018 related to restricted stock granted to its officers, employees and directors.

Performance Stock Units

Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the targeted number of PSUs stated in the agreement, contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period.

Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.

There were no grants or forfeitures of PSUs during the three months ended March 31, 2020. In January 2020, 77,485 shares of the PSUs granted in 2017 vested, of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. The Company recognized approximately $0.1 million in stock compensation expense related to PSUs during the three months ended March 31, 2020. As of March 31, 2020, an additional $0.6 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.6 years.

During the ~~six~~three months ended ~~June 30,~~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 ~~six~~three months ended ~~June 30,~~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 ~~$0.3 million~~$14 thousand in stock compensation expense related to PSUs during the ~~six~~three months ended ~~June 30,~~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 June 30, 2019, an additional $1.4 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.0 years.~~

During the six months ended June 30, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, which will be measured between January 1, 2018 and December 31, 2020, and were valued at a weighted average fair value of $7.69 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the six months ended June 30, 2018, 19,300 PSUs were forfeited by former employees. The Company recognized approximately $1.2 million in stock compensation expense related to PSUs during the six months ended June 30, 2018.

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019, ~~and 2018,~~ there was no excess tax benefit recognized.

Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 or ~~2018.~~2019.

During the ~~six~~three months ended ~~June 30,~~March 31, 2020, no stock options were exercised and stock options for 329 shares were forfeited by former employees. During the three months ended March 31, 2019, no stock options were exercised and stock options for 12,052 shares were forfeited by former employees.

6. Leases

During the ~~six~~three months ended ~~June 30, 2018, no stock options~~March 31, 2020, the Company entered into a new compressor contract with lease terms of twelve months or more, which qualifies as an operating lease. The Company also entered into new contracts for office equipment and a vehicle with lease terms of twelve months or more, which qualify as finance leases. As of March 31, 2020, the Company’s operating leases were ~~exercised or forfeited.~~

for compressors and office space at its two corporate offices and three field offices, while the Company’s finance leases were for vehicles and office equipment.

1617

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~~7. Leases~~

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

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

As of January 1, 2019, the majority of the Company’s operating leases were for field equipment, such as compressors. The adoption of ASC 842 did not have a material effect on the Company’s financial results or disclosures. Most of the Company’s compressor contracts which are on a month-to-month basis, and while it is probable the contract will be renewed on a monthly basis, the compressors can be easily substituted or cancelled by either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term. During the six months ended June 30, 2019, the Company entered into a new office lease and new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company also entered into a new office equipment contract, which qualifies as a finance lease, during the six months ended June 30, 2019. These leases do not have a material impact on the Company’ consolidated financial statements.

The following table summarizes the balance sheet information related to the Company’s leases as of ~~June 30,~~March 31, 2020 and December 31, 2019 (in thousands):

June 30, 2019

Operating lease right of use asset - current (1)
$
374

Operating lease right of use asset - long-term (2)

291

Total operating lease right of use asset
$
665

Operating lease liability - current (3)
$
(374)

Operating lease liability - long-term (4)

(291)

Total operating lease liability
$
(665)

Financing lease right of use asset - current (1)
$
17

Financing lease right of use asset - long-term (2)

69

Total financing lease right of use asset
$
86

Financing lease liability - current (3)
$
(15)

Financing lease liability - long-term (4)

(71)

Financing lease liability - current
$
(86)


	March 31, 2020		December 31, 2019
Operating lease right of use asset ⁽¹⁾	$	3,772	$	4,316

Operating lease liability - current⁽²⁾	$	(2,556)	$	(2,597)
Operating lease liability - long-term⁽³⁾		(1,202)		(1,738)
Total operating lease liability	$	(3,758)	$	(4,335)

Financing lease right of use asset⁽¹⁾	$	1,533	$	1,569

Financing lease liability - current⁽²⁾	$	(550)	$	(524)
Financing lease liability - long-term⁽³⁾		(994)		(1,051)
Total financing lease liability	$	(1,544)	$	(1,575)

(1)

Included in ~~“Other current~~“Right-of-use lease assets” on the consolidated balance sheet.

(2)

~~Included in “Other non-current assets” on the consolidated balance sheet.~~

~~(3)~~

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

~~(4)~~

(3)

Included in ~~“Other long-term~~“Lease liabilities” on the consolidated balance sheet.

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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 and financing lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment. For ~~operating~~ leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.

The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of ~~June 30,~~March 31, 2020 and December 31, 2019:


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

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


	March 31, 2020	December 31, 2019
Weighted Average Remaining Lease Terms (in years):
Operating leases	1.93	2.16
Financing leases	3.00	3.14

Weighted Average Discount Rate:
Operating leases	6.04%	6.04%
Financing leases	6.21%	6.24%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of ~~June 30, 2019,~~March 31, 2020, were as follows (in thousands):


	June 30, 2019
	Operating Leases		Financing Leases
2019 (remaining after June 30, 2019)	$	184	$	8
2020		358		16

					March 31, 2020
					Operating Leases		Financing Leases
2020 (remaining after March 31, 2020)					$	2,710	$	631
2021		114		17		825		527
2022		9		18		172		370
2023		-		18		170		150
2024		-		9		115		19
Total future minimum lease payments		665		86		3,992		1,697
Less: imputed interest		(38)		(14)		(234)		(153)
Present value of lease liabilities	$	627	$	72	$	3,758	$	1,544

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The following table summarizes expenses related to the Company’s leases for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019 (in thousands):


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

					Three Months Ended March 31, 2020		Three Months Ended March 31, 2019
Operating lease cost (1) (2)	$	100	$	471	$	687	$	371
Financing lease cost		-		-
Financing lease cost - amortization of right-of-use assets						135		-
Financing lease cost - interest on lease liabilities						24		-
Administrative lease cost (3)		18		37		19		19
Short-term lease cost (1) (4)		2,068		2,578		437		510
Total lease cost	$	2,186	$	3,086	$	1,302	$	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~~Costs related to an office leases and compressors with lease ~~which expired on March 31, 2019 and a new office lease which began on April 1, 2019.~~

terms of twelve months or more.

(3)

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

(4)

Costs related primarily to drilling ~~rig~~rigs, generators and compressor agreements with lease terms of more than one month and less than one year.

~~There~~During the three months ended March 31, 2020, there were ~~$0.1~~$0.7 million and $0.2 million in cash payments related to operating leases ~~during~~and financing leases, respectively. During the ~~six~~three months ended ~~June 30, 2019. No~~March 31, 2019, there were no cash payments related to operating leases or financing leases, as the operating lease payments did not begin until the second quarter of 2019, and there were ~~made for the~~no financing ~~lease during the six months ended June 30,~~leases as of March 31, 2019.

8.7. Other Financial Information

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


	June 30, 2019		December 31, 2018

					March 31, 2020		December 31, 2019
Accounts receivable:
Trade receivables(1)	$	3,370	$	6,052	$	12,003	$	21,110
Receivable for Alta Resources distribution		1,712		1,993		1,712		1,712
Joint interest billings		4,205		3,833		12,252		13,104
Income taxes receivable		848		424		268		509
Other receivables		1,006		223		3,324		4,126
Allowance for doubtful accounts		(994)		(994)		(994)		(994)
Total accounts receivable	$	10,147	$	11,531	$	28,565	$	39,567


Prepaid expenses and other:
Prepaid insurance	$	794	$	792	$	233	$	683
Other(2)		211	��	511		1,203		508
Total prepaid expenses and other	$	1,005	$	1,303	$	1,436	$	1,191


Accounts payable and accrued liabilities:
Royalties and revenue payable	$	12,580	$	17,986	$	46,765	$	49,644
Advances from partners(3)		7,693		1,785		120		6,733
Accrued exploration and development(3)		5,226		4,751		2,334		8,210
Accrued acquisition costs		3,763		4,352
Trade payables		12,185		3,385		10,993		14,086
Accrued general and administrative expenses		2,499		2,545
Accrued general and administrative expenses ⁽⁴⁾						11,589		12,037
Accrued operating expenses		2,144		1,801		5,362		5,794
Accrued short term leases						3,106		3,120
Other accounts payable and accrued liabilities		1,876		2,901		3,473		4,969
Total accounts payable and accrued liabilities	$	47,966	$	39,506	$	83,742	$	104,593

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(2)	Other prepaids primarily includes software licenses and additional licenses purchased for certain properties acquired from Will Energy and White Star in 2019.

(3)

Decrease in 2020 due to a decrease in drilling and completion activity during the three months ended March 31, 2020. In January 2020, the Company brought one West Texas well online but suspended further drilling in the area, and in its other onshore areas, in response to the dramatic decline in oil prices during the quarter.

(4)	Includes accruals for legal judgments, of which $6.3 million was paid in April 2020.See Note 11 – “Commitment and Contingencies” for further information.

Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ (in thousands):


		Six Months Ended June 30,
		2019		2018

						Three Months Ended March 31,
						2020		2019
Cash payments:
Interest payments	$	2,157	$	2,596	$	1,267	$	1,046
Income tax payments	$	805	$	81
Income tax payments (refunds)					$	(7)	$	40
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	475	$	(229)
Decrease in accrued capital expenditures					$	(4,676)	$	(2,220)

9.8. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at ~~June 30, 2019~~March 31, 2020 was approximately ~~$6.5~~$7.1 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results or production in those reported for the Company’s consolidated results.

The Company’s share in Exaro’s results of operations recognized for each of the three months ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~ was a gain of ~~$0.4~~$0.3 million, net of no tax expense, and a loss of $0.5 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, 2019 and 2018 was a gain of $0.7 million, net of no tax expense, and a gain of $0.2 million, net of no tax expense, respectively.expense.

9. Long-Term Debt

~~10. Indebtedness~~Credit Agreement

~~Credit Facility~~

~~The Company’s $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “Credit Facility”) currently matures on October 1, 2019.~~ On ~~June~~September 17, 2019, the Company entered into its new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the ~~Seventh~~closing of the acquisitions of certain producing assets and undeveloped acreage from Will Energy and White Star, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base was $145 million as of March 31, 2020. The borrowing base is subject to semi-annual redeterminations which will occur on May 1^st and November 1^st of each year. On June 9, 2020, the Company entered into the Second Amendment to the Credit ~~Facility~~Agreement (the ~~“Seventh~~“Second Amendment”). The ~~Seventh~~Second Amendment redetermined the borrowing base at ~~$85~~$95 million pursuant to the regularly scheduled redetermination ~~process, with a current availability limit of $75 million.~~process. The ~~Seventh~~Second Amendment also ~~set~~provides for, among other things, further $10 million automatic reductions in the ~~next~~ borrowing base ~~redetermination to August 1, 2019.~~ on each of June 30, 2020 and September 30, 2020. The borrowing base ~~under~~may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The Credit Agreement matures on September 17, 2024.

The Company initially incurred $1.8 million of arrangement and upfront fees in connection with the Credit ~~Facility effective August 1, 2019 has not yet been determined.~~Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, which is to be amortized over the five year term of the Credit Agreement. No fees were paid for the Second Amendment. As of March 31, 2020, the remaining balance of these fees was $3.1 million, which will be amortized through September 17, 2024.

As of ~~June 30, 2019 and December~~March 31, ~~2018,~~2020, the Company had approximately ~~$60.0~~$82.8 million outstanding under the Credit ~~Facility~~Agreement and $1.9 million in an outstanding letter of credit. As of ~~June 30,~~December 31, 2019, the Company had approximately $72.8 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of March 31, 2020, borrowing availability under the Credit ~~Facility~~Agreement was ~~$13.1~~$60.4 million.

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

Total interest expense under the ~~Credit Facility,~~Company’s current and previous credit agreements, including commitment fees, for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and March 31, 2019 was approximately $1.2 million and $1.1 million, ~~and $2.2 million,~~ respectively. ~~Total interest expense under the Credit Facility, including commitment fees, for the three and six months ended June 30, 2018 was approximately $1.3 million and $2.7 million, respectively.~~

The weighted average interest ~~rate~~rates in effect at ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018 was 5.9%~~2019 were 4.2% and ~~6.3%~~4.3%, respectively.

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

The Credit ~~Facility~~Agreement contains customary and typical restrictive ~~covenants which, among other things, require~~covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit ~~Facility.~~Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment also contains, among other things, an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, provides provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit ~~Facility~~Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, ~~audited financial statements that include~~ a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of ~~June 30, 2019,~~March 31, 2020, the Company was in compliance with all ~~but the Current Ratio covenant~~of its covenants under the Credit ~~Facility, and the Company obtained a waiver for such non-compliance effective June 30, 2019.~~Agreement.

~~Pursuit of Refinancing and Other Liquidity-Enhancing Initiatives~~

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

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~~11.~~10. 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,
	2019		2018		2019		2018

									Three Months Ended March 31,
									2020		2019
Current tax provision:
Federal	$	—	$	—	$	—	$	—	$	275	$	—
State		427		151		454		309		119		27
Total	$	427	$	151	$	454	$	309	$	394	$	27
Total tax provision:
Federal	$	—	$	—	$	—	$	—	$	275	$	—
State		427		151		454		309		119		27
Total income tax provision	$	427	$	151	$	454	$	309
Total income tax provision:									$	394	$	27

The Federal income tax expense results from an adjustment of the credit for previously paid Alternative Minimum Tax which was repealed and made refundable by the Tax Cuts and Jobs Act of 2017 (“TCJA”). The second half of the credit originally became refundable with the filed tax return for the tax year ended December 31, 2019. The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, modified this treatment, now allowing the Company to request an expedited refund of $0.9 million, which was previously accounted for as an income tax benefit when the TCJA was enacted. State income tax expense relates to expected income taxes for the quarter owed to the states of Louisiana and Oklahoma, imposed on properties within those states and, in each case, that are not shielded by existing Federal tax attributes.

Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). In addition, the Company used relief granted by the Oklahoma Tax Commission and the Louisiana Tax Commission to extend the due date for the first quarter estimated income tax payments to the states of Oklahoma and Louisiana to July 15, 2020. No Federal estimated tax payments for 2020 are expected. The Company does not expect to benefit from any other income tax-related provisions of the CARES Act.

In ~~recording~~assessing the realizability of 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 not 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~~temporary differences become deductible. The Company ~~believes that after considering all~~considers the ~~available objective evidence, both positive~~scheduled reversal of deferred tax liabilities, projected future taxable income and ~~negative,~~tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and ~~prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that~~projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will ~~be realized~~realize the benefits of these deductible differences and, therefore, ~~established a full~~adjusted valuation allowances for federal and state purposes to $126.3 million and $1.0 million, respectively, as of March 31, 2020. The $22.1 million net increase from the net valuation allowance recorded at ~~September 30, 2015. For~~December 31, 2019, like other items in the ~~six months ended June 30, 2019,~~

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company’s accounting for income taxes during the ~~Company continued to record~~current quarter, was determined using a ~~full valuation allowance against its net deferred~~specific March 31, 2020 cut-off date as an accurate estimate of 2020 pre-tax income or income tax ~~assets.~~expense cannot be reliably made at this time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

~~Income tax expense relates to current income taxes paid, or expected to be paid,~~As of March 31, 2020, the Company had federal net operating loss (“NOL”) carryforwards of approximately $383.9 million and state NOLs of $20.4 million. The Federal NOL carryforwards occurred due to the ~~State~~merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) and subsequent taxable losses during the years 2014 through 2019 due to lower commodity prices and utilization of ~~Louisiana on income from properties within the state that is not shielded by existing Federal tax attributes.~~

~~In the quarter ended December 31, 2018,~~various elections available to the Company ~~experienced an Ownership Change as described~~in expensing capital expenditures incurred in the development of oil and gas properties. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code ~~section~~Section 382 ~~as a result~~related to changes of ~~a completed follow-on equity offering. Management estimates that as a result~~more than 50% 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 portionownership of the Company’s ~~pre-2018~~stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. The CARES Act temporarily suspends the Section 172 limitation for NOLs ~~will expire unused. Due~~arising in tax years beginning in 2018, 2019 and 2020 and also allows NOLs originating in these years to be carried back five years; however, the ~~presence~~Company does not expect to receive any federal tax refunds from the temporary suspension of the ~~valuation allowance~~Section 172 limitation because the Company tax losses in each of the carryback years.

The Company experienced two separate Section 382 Ownership Changes in connection with two of its equity offerings occurring in 2018 and 2019, respectively (the “Ownership Changes”). Market conditions at the time of the 2019 Ownership Change had diminished from ~~prior years, this event~~the time of the 2018 Ownership Change, thus subjecting virtually all of the Company’s tax attributes to an annual limitation of $0.7 million a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future. For the quarter ended March 31, 2020, the Company did not have any activity which resulted in ~~no net charge to earnings. The Company is performing~~an 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.~~Section 382 Ownership Change.

~~12.~~11. Commitments and Contingencies

Legal Proceedings

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

In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of ~~decade-old~~decades-old poorly documented transactions. Based on prior summary judgments, the trial court ~~has~~ entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company ~~continues to vigorously defend this lawsuit and has~~ filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company ~~is awaiting a response from~~engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court

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as reconsider its initial decision to ~~whether it intends to~~not review the case. ~~In addition,~~That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company ~~is also~~recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds currently reflected in “Accounts payable and accrued liabilities” on the ~~process of seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals’ ruling.~~Company’s consolidated balance sheet. The judgment, interest and fees were paid in April 2020.

In ~~September 2012, a subsidiary of~~January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas ~~involving~~by a ~~title dispute over a 1/16th mineral interest~~third-party operator. The Company participated in the ~~producing intervals~~drilling of ~~certain wells operated by~~a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company inis responsible for the ~~Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred~~additional costs related to the ~~District Court for Liberty County, Texas~~drilling difficulties and ~~combined~~plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the

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plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a ~~suit filed by other parties against the plaintiff claiming ownership~~result of the ~~disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns~~judgment, during the three months ended September 30, 2019, the Company recorded an additional ~~1/16th unleased mineral interest in~~$2.1 million liability for 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).~~final judgment plus fees and interest. The Company has ~~made royalty payments~~since prepared and filed an appeal with ~~respect to~~ the ~~disputed interest in reliance, in part, upon leases obtained from successors to~~appellate court for a review of 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. Theinitial trial court ~~has entered judgment in favor of~~decision and is awaiting the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The trial court also awarded the Company a judgement against the plaintiff for approximately $1.0 million for reimbursement of legal fees. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. In December 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff filed a petition requesting that the matter be reviewed by the Texas Supreme Court. In June 2019, the Company received notice that the plaintiff’s petition would be denied. response

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

Throughput Contract Commitment

The Company signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and ~~currently forecasts it will continue~~continued to not meet the minimum throughput requirements under the agreement ~~based upon the current commodity price market and the Company’s short term strategic drilling plans. Without further development in that area, the volume deficiency will continue~~ through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in ~~April~~the second quarter of each calendar year. The Company incurred net fees of ~~$0.5~~$0.2 million during each of the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and ~~2018.~~2019. As of ~~June 30,~~December 31, 2019, the Company ~~estimates that the remaining net deficiency fee will be approximately $0.7~~has recorded a $1.0 million loss contingency through the expiration of the contract on March 31, 2020.

12. Subsequent Events

Paycheck Protection Program Loan

On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the CARES Act and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A.

The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.

Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during the eight-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to outstanding principal.

Sale of Assets

On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These properties were acquired during the Will Energy acquisition. The Company sold these properties in exchange for the buyer’s assumption of the asset retirement obligations associated with these wells, which is ~~currently accrued.~~an estimated $4.9 million net to the Company.

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Management Services Agreement

On June 5, 2020, the Company announced the addition of a new corporate strategy that includes offering a “fee for service” property management service for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million plus reimbursement of certain costs and expenses, an annual deferred fee of $2 million per year, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms of the warrants to be disclosed upon execution of the Warrant Agreement). Both companies and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owns approximately 56% of the common units in Mid-Con, and Travis Goff, the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.

Authorized Shares of Common Stock and Conversion of Series C Contingent Convertible Preferred Stock

On June 10, 2020, the Company filed an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock of the Company from 200,000,000 shares to 400,000,000 shares. The Charter Amendment and the conversion of 2,700,000 shares of the Company’s Series C contingent convertible preferred stock, par value $0.04 per share, into 2,700,000 shares of the Company’s common stock were approved by the stockholders of the Company on June 8, 2020, at the Company’s 2020 Annual Meeting of Stockholders. The shares of Series C contingent convertible preferred stock were issued in a private placement completed concurrently with a registered public offering of common stock in December 2019. Purchasers of the Series C contingent convertible preferred stock included John Goff, Wilkie Colyer and Farley Dakan.

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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 inwith our ~~2018~~2019 Form 10-K, previously filed with the Securities and Exchange Commission ("SEC").

Available Information

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and ~~current reports~~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”).~~SEC. This report should be read together with our ~~2018 Annual Report on~~2019 Form ~~10-K.~~10-K and our subsequent filings with the SEC. We are not including the information on our website as a part of, or incorporating it by reference into, this report.

Cautionary Statement about Forward-Looking Statements

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report and in our ~~2018 Annual Report on~~2019 Form 10-K and those factors summarized below:

●

~~our ability to continue as a going concern;~~

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

●

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

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

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

time and our ability to repay any excess borrowings as a result of such reduction;

●

our ability to successfully develop our undeveloped acreage in the Southern Delaware Basin and the Mid-continent area of Oklahoma, and realize the benefits associated therewith;

●

increased cost risks associated with our exploration and development in the Gulf of Mexico;

●

our financial position;

●

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

strategy or our new fee for service offering;

●

meeting our forecasts and budgets, including our ~~2019~~2020 capital expenditure budget;

●

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

●

~~volatility in natural gas, natural gas liquids~~outbreaks and ~~oil prices,~~pandemics, even outside our areas of operation, including ~~regional differentials;~~

COVID-19;

●

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;~~

explosions, onshore and offshore;

●

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

●

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

●

the costs associated with the offshore Iron Flea prospect and other offshore prospects;

●

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

●

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

program and support our acquisition efforts;

●

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

●

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

●

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

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●

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

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

●

interest rate volatility;

●

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

●

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

●

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

●

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

prices or other changes in the values of our assets;

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

strength and financial resources of competitors;

●

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

●

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to and maintain oil price and production controls;

●

the uncertain impact of supply of and demand for oil, natural gas and NGLs;

●

our ability to obtain goods and services critical to the operation of our properties;

●

worldwide and United States economic conditions;

●

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

●

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

●

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

●

expanded rigorous monitoring and testing requirements;

●

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

●

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

Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. Moreover, the effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of the factors summarized above or discussed in this report or our 2019 Form 10-K. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.

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

Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Overview

~~Overview~~

We are a Houston, Texas based, independent oil and natural gas ~~company.~~company, with regional offices in Oklahoma City and Stillwater, Oklahoma. 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, Oklahoma, Louisiana and Wyoming properties and to use that cash flow to explore, develop, exploit, ~~increase production from~~ and acquire ~~crude~~ oil and natural gas properties across the United States.

From the Company’s initial entry into the Southern Delaware Basin in 2016 and through mid-2019, the Company was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. As of March 31, 2020, the Company was producing from eighteen wells over our approximate 17,200 gross operated (8,000 company net) acre position in this West Texas area, prospective for the ~~onshore Texas~~Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

During the fourth quarter of 2019, we closed on the acquisitions of certain producing assets and undeveloped acreage of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) and established an additional core strategic area, primarily located in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative as production from these acquisitions represented 74% of our total net production for the first quarter of 2020.

In the fourth quarter of 2019, we also entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides us the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf ~~Coast and~~of Mexico. The first such exploratory prospect acquired was the ~~Rocky Mountain regions~~Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the ~~United States. On~~Louisiana coastline, which was spud in May 2020 and determined unsuccessful in June ~~14, 2019, following approval by our stockholders at the 2019 annual meeting of stockholders, we~~

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~~changed our state of incorporation from the State of Delaware to the State of Texas and increased our number of authorized shares of common stock from 50 million to 100 million.~~2020.

The following table lists our primary producing areas as of ~~June 30, 2019:~~March 31, 2020:

Location		Formation
Gulf of Mexico		Offshore Louisiana - water depths less than 300 feet
Mid-continent Region of Oklahoma		Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork
Southern Delaware Basin, Pecos County, Texas		Wolfcamp A and B
Madison and Grimes counties, Texas		Woodbine ~~(Upper Lewisville)~~/ Upper Lewisville
Zavala and Dimmit counties, Texas		Buda / Eagle Ford / Georgetown
San Augustine County, Texas		Haynesville shale, Mid Bossier shale and James Lime formations
Other Texas Gulf Coast		Conventional and smaller unconventional formations
Weston County, Wyoming		Muddy Sandstone
Sublette County, Wyoming		Jonah Field ⁽¹⁾

(1)

~~(1)~~

Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in our reported production results for all periods shown in this report.

Impact of the COVID-19 Pandemic and 2020 Plan Changes

The COVID-19 pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and has created significant volatility, uncertainty and turmoil in the oil and gas industry. This has led to a significant global oversupply of oil and a subsequent substantial decrease in oil prices. While global oil producers, including the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations reached an agreement to cut oil production in April 2020, downward pressure on commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for oil. We have certain commodity derivative instruments in place to mitigate the effects of such price declines; however, derivatives will not entirely mitigate lower oil prices. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond the Company’s control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, additional actions by businesses and governments in response to both the pandemic and the decrease in oil prices, the speed and effectiveness of responses to combat the virus, and the time necessary to equalize oil supply and demand to restore oil pricing. In response to these developments, we have implemented measures to mitigate the impact of the COVID-19 pandemic on our employees, operations and financial position. These measures include, but are not limited to, the following:

●

implemented work from home initiatives for all but critical staff and put in place social distancing measures;

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●

implemented a company wide effort to cut costs throughout our operations;

●

developed a plan to utilize our available storage capacity where possible to temporarily store a portion of our production; and

●

suspended any further plans for onshore drilling in 2020.

~~Capital Expenditures~~

~~Our 2019 capital program has focused,~~Additionally, on April 10, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and is administered by the U.S. Small Business Administration. Under the CARES Act, the PPP Loan may be partially or wholly forgiven if the funds are used for certain qualifying expenses. We intend to use the PPP Loan amount for qualifying expenses, and will continue to ~~focus,~~assess whether to apply for forgiveness of the PPP Loan in accordance with the terms of the CARES Act. See Item 1. Note 12 – “Subsequent Events” for additional information on the ~~development~~terms of ~~our approximate~~ the PPP Loan. We also benefited from certain income tax-related provisions of the CARES Act. See Item 1. Note 10 – “Income Taxes” for additional information

~~17,000 gross operated (8,100 total net) acres in~~ ~~our Southern Delaware Basin acreage in Pecos County, Texas. Due~~

We continue to ~~limited liquidity~~assess the global impacts of the COVID-19 pandemic and ~~near-term expiration of our credit facility (as discussed below), while we review liquidity-enhancing alternative sources of capital, we intend~~expect to continue to ~~minimize~~modify our ~~drilling program capital expenditures~~plans as more clarity around the full economic impact of COVID-19 becomes available. See Part II, Item 1A. "Risk Factors" for further discussion.

Capital Expenditures

During the three months ended March 31, 2020, we brought one well online in the Southern Delaware ~~Basin. In addition, until a sustained improvement~~Basin, the State Spearhead #1H, which is located in ~~commodity~~our NE Bullseye project area but suspended further drilling in the area in response to the dramatic decline in oil prices ~~occurs,~~during the quarter. Additionally, due to the recent decline in oil prices, we ~~will commit~~have suspended any further plans for onshore 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~~2020. The offshore Iron Flea prospect in the ~~Southern Delaware Basin related to constrained production takeaway capacity,~~shallow waters off of the Louisiana coast in Grand Isle was spud in late May 2020. On June 12, 2020, the target drilling depth was reached, and the adverse impact on commodity price differentials, we still generate positive returns to date on our drilling investment. We continuously monitor the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, will make adjustments to our capital program as the year progresses. We will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales.prospect was determined unsuccessful.

~~Additionally,~~

For 2020, we will continue to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which we can leverage our geological and operational experience and expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to economically grow production and add reserves.

~~Southern Delaware Basin (West Texas)~~

As of December 31, 2018, we had nine wells producing from the Wolfcamp A formation, three wells producing from the Wolfcamp B formation, and a fourth Wolfcamp B well, the Ripper State #2H, which was drilled in November 2018. The Ripper State #2H was recently completed and ~~initiated flow back in late July 2019.~~

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

On March 19, 2019, we spud the Iron Snake #1H, targeting the Wolfcamp B formation. This well was drilled to a total measured depth of approximately 20,500 feet, including an approximate 10,100 foot lateral. Completion operations are expected to begin in September 2019, with production expected to begin in the fourth quarter.

On June ~~3, 2019, we spud~~5, 2020, the ~~Breakthrough State #1H, targeting~~Company announced the ~~Wolfcamp A formation. This well was drilled~~addition of a new corporate strategy that includes offering a “fee for service” property management service for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a ~~total measured depth~~Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) (Nasdaq: MCEP) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million plus reimbursement of certain costs and expenses, an annual deferred fee of $2 million per year, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms to be disclosed upon execution of the Warrant Agreement). Both companies and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owns approximately ~~20,300 feet, including an approximate 9,800 foot lateral. Completion operations~~56% of the common units in Mid-Con, and Travis Goff, the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.

Impairment of Long-Lived Assets

Under 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 ~~expected~~lower than the unamortized capitalized cost, then the capitalized cost is reduced to ~~begin later this fall, with production expected to begin~~fair value. In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the ~~fourth quarter.~~

global demand for oil, combined with the failure by the OPEC and Russia to reach an agreement on lower production quotas in March 2020, caused a dramatic increase in the supply of oil and a corresponding decrease in commodity prices, and lowered the demand for all commodity products. Consequently, during the three months ended March 31, 2020, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties related to the dramatic decline in commodity prices, as discussed above, the “PV-10” (present value, discounted at a 10%

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rate) of our proved reserves, and the associated change in our current development plans for our proved, undeveloped locations. No impairment of proved properties was recorded during the three months ended March 31, 2019.

~~On July 4,~~

We recorded a $2.6 million non-cash charge for unproved impairment expense during the three months ended March 31, 2020. The impairment primarily related to acquired leases in the Company’s Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. During the three months ended March 31, 2019, we spud the Old Ironside #1H, targeting the Wolfcamp A formation. This well was drilled to a total measured depth of approximately 20,400 feet, including an approximate 9,900 foot lateral, with completion operations expected to begin later this fall and production expected to begin in the fourth quarter.

~~Impairment of Long-Lived Assets~~

We recognized non-cash proved property impairment of $0.2 million for the six months ended June 30, 2019, related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018. Under GAAP, an impairment charge is required when the unamortized capital cost of any individual property within the Company’s producing property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves for that property. We recognizedrecorded non-cash impairment expense of ~~approximately $0.9~~$0.5 million ~~for the six months ended June 30, 2019,~~ related to impairment of certain unproved properties, primarily due to expiring leases.

~~Going Concern Assessment~~

As discussed below under “Capital Resources and Liquidity”, our Credit Facility (as defined in “Capital Resources and Liquidity”) currently matures on October 1, 2019. Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our existing Credit Facility. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. 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.

Summary Production Information

Our production for the three months ended ~~June 30, 2019~~March 31, 2020 was approximately ~~59%~~85% onshore and 15% offshore, ~~and 41% onshore,~~ volumetrically, and was comprised of ~~55%~~50% natural gas, ~~26%~~30% oil and ~~19%~~20% natural gas liquids. Our production for the three months ended ~~June 30, 2018~~March 31, 2019 was ~~56%~~35% onshore and 65% offshore, ~~and 44% onshore,~~ volumetrically, and was comprised of approximately 59% natural gas, ~~24%~~23% oil and ~~17%~~18% natural gas liquids.

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

Three Months Ended


June 30, 2018

September 30, 2018

December 31, 2018

March 31, 2019

June 30, 2019

Offshore (1)

23.7

27.2

25.3

23.5

19.1

West Texas

6.7

6.4

7.5

5.9

5.9

Other Onshore (2)

12.0

10.0

7.0

6.5

7.3

42.4

43.6

39.8

35.9

32.3


	Three Months Ended
	March 31, 2019	June 30, 2019	September 30, 2019	December 31, 2019	March 31, 2020
Offshore GOM	3.9	3.2	3.3	3.2	2.7
Central Oklahoma ⁽¹⁾	—	—	—	8.1	10.9
Western Anadarko ⁽¹⁾	—	—	—	1.7	2.9
West Texas ⁽²⁾	1.0	1.0	0.9	1.4	1.2
Other Onshore	1.1	1.2	1.4	1.4	1.2
	6.0	5.4	5.6	15.7	18.9

(1)

~~(1)~~

~~Our Vermilion 170 well was sold effective December 1, 2018~~Properties acquired in the White Star and ~~produced at an average daily rate of 2.2 Mmcfe/d~~Will Energy acquisitions during ~~2018. The~~the three months ended ~~June 30, 2019 included a decreased production rate of approximately 1.9 Mmcfe/d due to downtime for pipeline and compressor repair and maintenance.~~

December 31, 2019.

(2)

~~(2)~~

Includes Woodbine production from Madison and Grimes counties and conventional production in others; Eagle Ford and Buda production from Zavala and Dimmit counties; and wells in East Texas and Wyoming. DecreaseIncrease in production during the three months ended December 31, ~~2018 is primarily~~2019 was due to ~~the Liberty and Hardin County property sale in November 2018.~~

new wells coming online.

Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, owns a 37% ownership interest in Exaro. As of ~~June 30, 2019,~~March 31, 2020, Exaro had ~~648~~645 wells on production over its 5,760 gross acres (1,040 net), with a working interest between ~~2.4%~~14.6% and 32.5%.

~~Table of Contents~~

These wells were producing at a rate of approximately ~~19 Mmcfe/~~2.7 Mboe/d, net to Exaro. As a result of our equity investment in Exaro, we recognized ~~an investment~~a gain of approximately ~~$0.4 million, net of no tax expense, and an investment loss of approximately $0.5~~$0.3 million, net of no tax expense, for each of the three months ended ~~June 30,~~March 31, 2020 and 2019, and 2018, respectively. We recognized an investment gain of approximately $0.7 million, net of no tax expense, and an investment gain of approximately $0.2 million, net of no tax expense, for the six months ended June 30, 2019 and 2018, respectively. See Item 1. Note ~~9 to our Financial Statements -~~8 – “Investment in Exaro Energy III LLC” for additional details related to this equity 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. In June 2019, we also sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the sold properties.

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Results of Operations for the Three Months ended March 31, 2020 and ~~Six Months Ended June 30,~~ 2019 ~~and 2018~~

The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from operations for the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018. Oil,~~2019. Natural gas is compared with oil, condensate and NGLs ~~are compared with natural gas~~ in terms of ~~cubic feet~~thousands of ~~natural gas equivalents. One barrel~~barrels of oil ~~condensate or NGL is the energy equivalent of six~~equivalents. Six thousand cubic feet (“Mcf”) of natural ~~gas.~~gas is the energy equivalent of one barrel of oil, condensate or NGL. Reported operating expenses include production taxes, such as ad valorem and severance taxes.


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


													Three Months Ended March 31,
													2020		2019		%

Revenues (thousands):
Oil and condensate sales	$	7,439	$	9,607	(23)	%	$	13,845	$	18,418	(25)	%	$	22,782	$	6,406	256	%
Natural gas sales		3,857		5,848	(34)	%		9,499		14,457	(34)	%		8,170		5,642	45	%
NGL sales		1,466		2,993	(51)	%		3,429		6,010	(43)	%		3,621		1,963	84	%
Total revenues	$	12,762	$	18,448	(31)	%	$	26,773	$	38,885	(31)	%	$	34,573	$	14,011	147	%


Production:
Oil and condensate (thousand barrels)
Offshore GOM		10		18	(44)	%		23		37	(38)	%		9		13	(31)	%
Central Oklahoma														289		—	100	%
Western Anadarko														77		—	100	%
West Texas		60		70	(14)	%		125		122	2	%		89		64	39	%
Other Onshore		57		63	(10)	%		105		133	(21)	%		56		48	17	%
Total oil and condensate		127		151	(16)	%		253		292	(13)	%		520		125	316	%
Natural gas (million cubic feet)
Offshore GOM		1,325		1,695	(22)	%		2,960		3,991	(26)	%		1,263		1,635	(23)	%
Central Oklahoma														2,817		—	100	%
Western Anadarko														827		—	100	%
West Texas		88		80	10	%		152		126	21	%		50		64	(22)	%
Other Onshore		215		504	(57)	%		409		1,075	(62)	%		244		194	26	%
Total natural gas		1,628		2,279	(29)	%		3,521		5,192	(32)	%		5,201		1,893	175	%
Natural gas liquids (thousand barrels)
Offshore GOM		58		59	(2)	%		124		137	(9)	%		30		66	(55)	%
Central Oklahoma														232		—	100	%
Western Anadarko														46		—	100	%
West Texas		15		18	(17)	%		29		25	16	%		9		14	(36)	%
Other		19		34	(44)	%		37		74	(50)	%
Other Onshore														16		18	(11)	%
Total natural gas liquids		92		111	(17)	%		190		236	(19)	%		333		98	240	%
Total (million cubic feet equivalent)
Total (thousand barrels of oil equivalent)
Offshore GOM		1,736		2,156	(19)	%		3,847		5,033	(24)	%		250		352	(29)	%
Central Oklahoma														991		—	100	%
Western Anadarko														261		—	100	%
West Texas		541		606	(11)	%		1,075		1,008	7	%		106		89	19	%
Other Onshore		665		1,092	(39)	%		1,255		2,317	(46)	%		112		98	14	%
Total production		2,942		3,854	(24)	%		6,177		8,358	(26)	%		1,720		539	219	%


Daily Production:
Oil and condensate (thousand barrels per day)
Offshore GOM		0.1		0.2	(44)	%		0.1		0.2	(38)	%		0.1		0.1	(31)	%
Central Oklahoma														3.2		—	100	%
Western Anadarko														0.8		—	100	%
West Texas		0.7		0.8	(14)	%		0.7		0.7	2	%		1.0		0.7	39	%
Other Onshore		0.6		0.7	(10)	%		0.6		0.7	(21)	%		0.6		0.6	17	%
Total oil and condensate		1.4		1.7	(16)	%		1.4		1.6	(13)	%		5.7		1.4	316	%
Natural gas (million cubic feet per day)
Offshore GOM		14.6		18.6	(22)	%		16.4		22.1	(26)	%
West Texas		1.0		0.9	10	%		0.8		0.7	21	%
Other Onshore		2.3		5.5	(57)	%		2.3		5.9	(62)	%
Total natural gas		17.9		25.0	(29)	%		19.5		28.7	(32)	%
Natural gas liquids (thousand barrels per day)
Offshore GOM		0.6		0.6	(2)	%		0.7		0.8	(9)	%
West Texas		0.2		0.2	(17)	%		0.2		0.1	16	%
Other		0.2		0.4	(44)	%		0.1		0.4	(50)	%
Total natural gas liquids		1.0		1.2	(17)	%		1.0		1.3	(19)	%

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

Total (million cubic feet equivalent per day)

													Three Months Ended March 31,
													2020		2019		%

Natural gas (million cubic feet per day)
Offshore GOM		19.1		23.7	(19)	%		21.3		27.8	(24)	%		13.9		18.2	(23)	%
Central Oklahoma														31.0		—	100	%
Western Anadarko														9.1		—	100	%
West Texas														0.5		0.7	(22)	%
Other Onshore														2.7		2.1	26	%
Total natural gas														57.2		21.0	175	%
Natural gas liquids (thousand barrels per day)
Offshore GOM														0.3		0.7	(55)	%
Central Oklahoma														2.5		—	100	%
Western Anadarko														0.5		—	100	%
West Texas														0.1		0.2	(36)	%
Other Onshore														0.3		0.2	(11)	%
Total natural gas liquids														3.7		1.1	240	%
Total (thousand barrels of oil equivalent per day)
Offshore GOM														2.7		3.9	(29)	%
Central Oklahoma														10.9		—	100	%
Western Anadarko														2.9		—	100	%
West Texas		5.9		6.7	(11)	%		5.9		5.6	7	%		1.2		1.0	19	%
Other Onshore		7.3		12.0	(39)	%		6.9		12.8	(46)	%		1.2		1.1	14	%
Total production		32.3		42.4	(24)	%		34.1		46.2	(26)	%		18.9		6.0	219	%


Average Sales Price:
Oil and condensate (per barrel)	$	58.42	$	63.53	(8)	%	$	54.78	$	63.16	(13)	%	$	43.77	$	51.08	(14)	%
Natural gas (per thousand cubic feet)	$	2.37	$	2.57	(8)	%	$	2.70	$	2.78	(3)	%	$	1.57	$	2.98	(47)	%
Natural gas liquids (per barrel)	$	16.01	$	26.84	(40)	%	$	18.05	$	25.32	(29)	%	$	10.89	$	19.96	(45)	%
Total (per thousand cubic feet equivalent)	$	4.34	$	4.79	(9)	%	$	4.33	$	4.65	(7)	%

Total (per barrels of oil equivalent)													$	20.10	$	25.98	(23)	%

Expenses (thousands):
Operating expenses	$	5,694	$	6,478	(12)	%	$	10,886	$	13,405	(19)	%	$	21,483	$	5,192	314	%
Exploration expenses	$	249	$	394	(37)	%	$	473	$	863	(45)	%	$	398	$	224	78	%
Depreciation, depletion and amortization	$	7,573	$	9,498	(20)	%	$	15,129	$	19,983	(24)	%	$	12,854	$	7,556	70	%
Impairment and abandonment of oil and gas properties	$	1,247	$	777	60	%	$	1,834	$	4,104	(55)	%	$	145,878	$	587	*	%
General and administrative expenses	$	4,456	$	5,354	(17)	%	$	9,461	$	12,080	(22)	%	$	5,425	$	5,005	8	%
Gain (loss) from investment in affiliates (net of taxes)	$	427	$	(475)	(190)	%	$	457	$	232	97	%

Selected data per Mcfe:
Gain from investment in affiliates (net of taxes)													$	286	$	30	853	%

Selected data per Boe:
Operating expenses	$	1.94	$	1.68	15	%	$	1.76	$	1.60	10	%	$	12.49	$	9.63	30	%
General and administrative expenses	$	1.51	$	1.39	9	%	$	1.53	$	1.45	6	%	$	3.15	$	9.29	(66)	%
Depreciation, depletion and amortization	$	2.57	$	2.46	4	%	$	2.45	$	2.39	3	%	$	7.47	$	14.02	(47)	%

*Greater than 1,000%

Three Months Ended ~~June 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~June 30, 2018~~March 31, 2019

Natural Gas, Oil and NGL Sales and Production

All of our revenues are from the sale of our natural gas, oil, NGL and ~~NGL~~water 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. As discussed above, oil prices declined significantly in the first quarter of 2020 as a result of the effects of the COVID-19 pandemic and the ongoing disruptions to the global energy markets. Our production volumes are subject to significant variation as a result of new operations, weather events, transportation and processing constraints and mechanical issues. In addition, our production from individual wells naturally declines over time as we produce our reserves.

Table of Contents

We reported revenues of ~~$12.8~~$34.6 million for the three months ended ~~June 30, 2019,~~March 31, 2020, compared to revenues of ~~$18.4~~$14.0 million for the three months ended ~~June 30, 2018. The decrease in revenues was primarily~~March 31, 2019, an increase, even as prices declined, attributable to ~~lower natural gas~~the production ~~which was mostly related to non-core property sales~~from the properties acquired from Will Energy and offshore downtime for pipeline and compressor repair and maintenance, as well as the expected year over year decline in our offshore properties. The decrease in revenues was also due to lower oil production related to the temporary suspension of our drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 because of the unstable oil price environment,White Star.

Total equivalent production was ~~32.3 Mmcfe/~~18.9 Mboe/d for the three months ended ~~June 30, 2019,~~March 31, 2020, compared to ~~42.4 Mmcfe/~~6.0 Mboe/d in the prior year quarter, an increase attributable to the additional production from the Will Energy and White Star acquisitions. Net oil production for the current quarter was approximately 5.7 Mbbl/d, compared with approximately 1.4 Mbbl/d in the prior year quarter. Net natural gas production for the ~~three months ended June 30, 2019~~current quarter was approximately ~~17.9~~ 57.2 Mmcf/d, compared with approximately ~~25.0~~21.0 Mmcf/d ~~for~~in the three months ended June 30, 2018, with approximately 80% of the decline related to non-core property sales, and the remainder primarily due to downtime associated with offshore pipeline and compressor repair and maintenance and normal field decline in our offshore properties. NGL production decreased from approximately 1,200 barrels per day to 1,000 barrels per day, mostly related to non-core property sales. Net oil production decreased from approximately 1,700 barrels per day to 1,400 barrels per day primarily due to the temporary suspension of our drilling program in West Texas for the fourthprior year quarter, ~~of 2018 and first quarter of 2019. The higher-unit value oil~~ and NGL production (but lower volume equivalency than gas) increased from 41% to 45% of total production due to our focus on our oil-weighted West Texas drilling program. West Texas accounted for 18% of total equivalent production for the ~~three months ended June 30, 2019, as~~current quarter was approximately 3.7 Mbbl/d, compared ~~to 16% of total equivalent production for~~with approximately 1.1 Mbbl/d in the ~~three months ended June 30, 2018.~~ prior year quarter.

~~Table of Contents~~

Average Sales Prices

The average equivalent sales price realized for the three months ended ~~June 30, 2019~~March 31, 2020 was ~~$4.34~~$20.10 per ~~Mcfe~~Boe compared to ~~$4.79~~$25.98 per ~~Mcfe~~Boe for the three months ended ~~June 30, 2018. This decrease~~March 31, 2019. The decline was attributable ~~primarily~~ to the decrease in all realized commodity prices in the current year quarter, as a result of the decrease in demand for commodity products due to the COVID-19 pandemic and the failure of OPEC and Russia to reach an agreement on oil production quotas in March 2020. The realized price of oil was $43.77 per Bbl in the current quarter, compared to ~~$58.42~~$51.08 per ~~barrel from $63.53~~Bbl in the prior year quarter. The realized price of gas was $1.57 per ~~barrel for~~Mcf in the ~~three months ended June 30, 2018,~~current quarter compared to $2.98 per Mcf in the prior year quarter, and ~~to the decrease in~~ the realized price of NGLs was $10.89 per Bbl in the current quarter compared to ~~$16.01~~$19.96 per ~~barrel, from $26.84 per barrel for~~Bbl in the ~~three months ended June 30, 2018.~~ prior year quarter.

Operating Expenses

Operating expenses for the three months ended ~~June 30, 2019~~March 31, 2020 were approximately ~~$5.7~~$21.5 million, or ~~$1.94~~$12.49 per ~~Mcfe,~~Boe, compared to ~~$6.5~~$5.2 million, or ~~$1.68~~$9.63 per ~~Mcfe,~~Boe, for the three months ended ~~June 30, 2018.~~March 31, 2019. The table below provides additional detail of operating expenses for ~~each of~~ the three month periods:


	Three Months Ended June 30,
	2019			2018
	(in thousands)		(per Mcfe)	(in thousands)		(per Mcfe)

							Three Months Ended March 31,
							2020			2019
							(in thousands)		(per Boe)	(in thousands)		(per Boe)
Lease operating expenses	$	3,629	$ 1.23	$	4,852	$ 1.26	$	13,051	$ 7.59	$	3,685	$ 6.84
Production & ad valorem taxes		657	0.22		836	0.22		1,746	1.02		386	0.72
Transportation & processing costs		502	0.17		285	0.07		5,552	3.23		695	1.29
Workover costs		906	0.32		505	0.13		1,134	0.65		426	0.78
Total operating expenses	$	5,694	1.94	$	6,478	$ 1.68	$	21,483	12.49	$	5,192	$ 9.63

Lease operating expenses ~~decreased from $4.9~~increased $9.4 million ~~during~~compared to the ~~three months ended June 30, 2018 to $3.6 million for the three months ended June 30, 2019, primarily~~prior year quarter, due to the addition of our ~~non-core property sales.~~acquired properties.

Production and ad valorem ~~expenses decreased from $0.8~~taxes increased $1.4 million ~~during~~compared to the ~~three months ended June 30, 2018~~prior year quarter, primarily related to the Will Energy and White Star property acquisitions.

Transportation and processing costs increased $4.9 million compared to the prior year quarter due to additional transportation expense of $5.1 million, primarily related to the properties acquired in the White Star acquisition.

Workover costs increased $0.7 million for the three months ended ~~June 30, 2019,~~March 31, 2020, compared to the prior year quarter, primarily ~~as a result of lower production associated with our non-core property sales.~~

Transportation and processing costs increased from $0.3 million during the three months ended June 30, 2018 to $0.5 million for the three months ended June 30, 2019, primarily due to a prior period adjustment related to ~~an offshore processing fee overcharge, which caused 2018 costs to be lower than usual.~~workovers on properties acquired from White Star.

Impairment and Abandonment Expenses

During the three months ended ~~June 30, 2019,~~March 31, 2020, we ~~recognized $0.2~~recorded a $143.3 million in non-cash charge for proved property impairment ~~related to leases~~of our onshore properties as a result of the dramatic decline in ~~Wyoming~~commodity prices, the “PV-10” (present value, discounted at a 10% rate) of our proved reserves, and ~~an onshore non-operated property~~the associated change in ~~an area previously impaired due to revised reserve estimates made~~our current development plans for proved, undeveloped locations. No impairment of proved properties was recorded during the ~~quarter~~three months ended ~~December~~March 31, ~~2018.~~ 2019.

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During the three months ended ~~June 30, 2018,~~March 31, 2020, we ~~recognized $0.4~~recorded a $2.6 million in non-cash ~~proved property impairment due to revised reserve estimates. We recognized non-cash~~charge for unproved impairment expense related primarily to acquired leases in our Central Oklahoma and Western Anadarko regions, which will be expiring in 2020, and which we have no current plans to develop as a result of ~~approximately $0.4 million, primarily related to expiring leases, during each of~~the current commodity price environment. During the three months ended ~~June 30,~~March 31, 2019, ~~and June 30, 2018. We recognized abandonment~~we recorded non-cash impairment expense of ~~approximately $0.6~~$0.5 million ~~during the three months ended June 30, 2019. An immaterial amount~~related to impairment of ~~abandonment expense was recognized during the three months ended June 30, 2018.~~certain unproved properties, primarily due to expiring leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the three months ended June 30, 2019 was approximately $7.6 million, or $2.57 per Mcfe. This compares to approximately $9.5 million, or $2.46 per Mcfe, for the three months ended June 30, 2018. The lower depletion expense for the three months ended ~~June 30, 2019~~March 31, 2020, was approximately $12.9 million, or $7.47 per Boe. This compares to approximately $7.6 million, or $14.02 per Boe, for the three months ended March 31, 2019. The higher depletion expense in the current quarter was attributable to $7.8 million of additional expense recognized for our acquired properties, while the lower ~~production.~~unit rate reflects the lower purchase price per barrel for our acquired properties ($6.08 per Boe) and a reduction in the Gulf of Mexico rate due to impairment recorded during the fourth quarter of 2019.

General and Administrative Expenses

Total general and administrative expenses for the three months ended ~~June 30, 2019~~March 31, 2020 were approximately ~~$4.5~~$5.4 million, compared to ~~$5.4~~$5.0 million for the three months ended ~~June 30, 2018.~~March 31, 2019.

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


	Three Months Ended June 30,
	2019		2018
	(in thousands)
Wages and benefits (1)	$	1,206	$	1,719

					Three Months Ended March 31,
					2020		��	2019
					(in thousands)
Wages, bonuses and employee benefits ⁽¹⁾					$	2,568		$	850
Non-cash stock-based compensation ~~(1)~~(2)		584		1,583		350			1,052
Professional fees ~~(2)~~(3)		1,021		754		1,616			1,107
Professional fees - special ~~(3)~~(4)		985		—		783			751
Other ~~(4)~~(5)		660		1,298		108			1,245
Total general and administrative expenses	$	4,456	$	5,354	$	5,425		$	5,005

(1)	~~(1)~~ Higher expenses for the three months ended March 31, 2020 due to the acquisition of White Star employees during the three months ended December 31, 2019.

(2)

Lower expense ~~primarily~~for the three months ended March 31, 2020, due to ~~lower head count in 2019.~~

no stock grants awarded during the quarter.

(3)

~~(2)~~

Primarily includes fees related to recurring legal counsel, technical consultants and accounting and ~~auditing.~~

auditing costs.

(4)

~~(3)~~

Non-recurring fees incurred in conjunction with our pursuit of strategic ~~initiatives.~~

initiatives, including the integration of the White Star and Will Energy assets acquired during the three months ended December 31, 2019.

(5)

~~(4)~~

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

The 2019 expenses included an additional $0.4 million in rent for our Houston office lease which expired on March 31, 2019 and was renewed on April 1, 2019 at a lower monthly rate.

Gain ~~(Loss)~~ from Affiliates

For the ~~quarters~~three months ended ~~June 30,~~March 31, 2020 and March 31, 2019, ~~and June 30, 2018,~~ we recorded a gain from affiliates of approximately ~~$0.4 million, net of no tax expense, and a loss of $0.5~~$0.3 million, net of no tax expense, respectively, related to our equity investment in Exaro.

~~Gain from Sale~~Capital Resources and Liquidity

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on debt. Our primary sources of ~~Assets~~liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our Credit Agreement (as defined below).

During the three months ended ~~June 30, 2019,~~March 31, 2020, we ~~recorded a gain~~incurred expenditures of approximately $4.0 million on ~~sale of assets of $0.4~~capital projects, including $2.0 million ~~primarily related to post-closing adjustments from sales of non-core properties during 2018~~for our drilling and ~~2019. During~~completion program in the ~~three months ended June 30, 2018 we recorded a gain on sale of assets of $1.4 million related to the sale of our non-operated assets in Starr County, Texas.~~

~~Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018~~

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

~~All of our revenues are from the sale of our natural gas, oil and NGL production. Our revenues may vary significantly from year to year depending~~Southern Delaware Basin. We brought one newly-drilled West Texas well on production ~~volumes~~ and ~~changes~~commenced the drilling of a salt water disposal well in ~~commodity prices, each of which may fluctuate widely. Our production volumes are subject to significant variation as~~West Texas. Additionally, we paid a ~~result of new operations, weather events, transportation and processing constraints and mechanical issues. In addition, our production naturally declines over time as we produce our reserves.~~

~~We reported revenues of $26.8~~$7.1 million deposit for the ~~six months ended June 30, 2019, compared~~turnkey drilling of the offshore Iron Flea prospect, currently included in “Deposits and other” on our consolidated balance sheet at March 31, 2020, which will be reclassed to ~~revenues~~exploration expense in the second quarter of $38.9 million for the six months ended June 30, 2018. The decrease in revenues was primarily attributable to lower natural gas production, which was mostly related to non-core property sales, offshore downtime for pipeline and compressor repair and maintenance and the expected year over year decline in our offshore properties. The decrease in revenues was also2020, due to the ~~temporary suspension of our drilling program in West Texas for the fourth~~well being unsuccessful. The current quarter ~~of 2018 and first quarter of 2019 because of the unstable oil price environment.~~

Total equivalent production was 34.1 Mmcfe/d for the six months ended June 30, 2019, compared to 46.2 Mmcfe/d in the prior year quarter. Net natural gas production for the six months ended June 30, 2019 was approximately ~~19.5~~ Mmcf/d, compared with approximately 28.7 Mmcf/d for the six months ended June 30, 2018, with approximately half of the decline related to non-core property sales, and the remainder primarily due to normal field decline in our offshore properties. NGL production decreased from approximately 1,300 barrels per day to 1,000 barrels per day, mostly related to non-core property sales. Net oil production decreased from approximately 1,600 barrels per day to 1,400 barrels per day primarily due to the temporary suspension of our drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019. The higher-unit value oil and NGL production (but lower volume equivalency than gas) increased from 38% to 43% of total production due to our focus on our oil-weighted West Texas drilling program. West Texas accounted for 17% of total equivalent production for the six months ended June 30, 2019, as compared to 12% of total equivalent production for the six months ended June 30, 2018.

also included

~~Average Sales Prices~~

The average equivalent sales price realized for the six months ended June 30, 2019 was $4.33 per Mcfe compared to $4.65 per Mcfe for the six months ended June 30, 2018. This decrease was attributable primarily to the decrease in the realized price of oil to $54.78 per barrel, from $63.16 per barrel for the six months ended June 30, 2018, and to the decrease in the realized price of NGLs to $18.05 per barrel, from $25.32 per barrel for the six months ended June 30, 2018.

~~Operating Expenses~~

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

Six Months Ended June 30,

2019

2018

(in thousands)

(per Mcfe)


(in thousands)

(per Mcfe)

Lease operating expenses

$
7,314

$ 1.17

$
9,896

$ 1.18

Production & ad valorem taxes

1,043

0.17

1,618

0.19

Transportation & processing costs

1,197

0.19

882

0.11

Workover costs

1,332

0.23

1,009

0.12

Total operating expenses

$
10,886

1.76

$
13,405

$ 1.60

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

Production and ad valorem expenses decreased from $1.6 million during the six months ended June 30, 2018 to $1.0 million for the six months ended June 30, 2019, primarily as a result of lower production associated with our non-core property sales.

Transportation and processing costs increased from $0.9 million during the six months ended June 30, 2018 to $1.2 million for the six months ended June 30, 2019, primarily due to the final accrual in 2019 for our estimated remaining throughput commitment fee in Southeast Texas, and a prior period credit related to an offshore processing fee overcharge, which caused 2018 costs to be lower than usual. See Note 12 – “Commitments and Contingencies” for further information regarding the throughput commitment fee.

~~Impairment and Abandonment Expenses~~

During the six months ended June 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to expiring leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018, compared to $2.7 million in non-cash impairment charges for the six months ended June 30, 2018, related to revised reserve estimates of onshore and offshore proved properties. During the six months ended June 30, 2019 and 2018, we recognized non-cash impairment expense of approximately $0.9 million and approximately $1.2 million, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. We recognized abandonment expense of approximately $0.7 million and $0.2 million during the six months ended June 30, 2019 and June 30, 2018, respectively.

~~Depreciation, Depletion and Amortization~~

Depreciation, depletion and amortization for the six months ended June 30, 2019 was approximately $15.1 million, or $2.45 per Mcfe. This compares to approximately $20.0 million, or $2.39 per Mcfe, for the six months ended June 30, 2018. The lower depletion expense for the six months ended June 30, 2019 was attributable to lower production.

~~General and Administrative Expenses~~

~~Total general and administrative expenses for the six months ended June 30, 2019 were approximately $9.5 million, compared to $12.1 million for the six months ended June 30, 2018.~~

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

Six Months Ended June 30,

2019

2018

(in thousands)

Wages and benefits (1)

$
2,057

$
4,442

Non-cash stock-based compensation (1)

1,637

3,008

Professional fees (2)

2,128

2,040

Professional fees - special (3)

1,736

—

Other (4)

1,903

2,590

Total general and administrative expenses

$
9,461

$
12,080

~~(1)~~

~~Lower expense primarily due to lower head count in 2019.~~

~~(2)~~

~~Primarily includes fees related to recurring legal, consultants, and accounting and auditing.~~

~~(3)~~

~~Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives.~~

~~(4)~~

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

~~Gain from Affiliates~~

For the six months ended June 30, 2019 and June 30, 2018, we recorded a gain from affiliates of approximately $0.7 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.

~~Gain from Sale of Assets~~

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

~~Capital Resources and Liquidity~~

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

Our capital expenditure program for the year 2020 is forecast at approximately $16.4 million. Due to the low and volatile commodity price environment, the Company has suspended any further plans for ~~2019 is approximately $35.1 million, including $29.2 million~~onshore drilling and completions in ~~the Southern Delaware Basin. For the rest of 2019, we have budgeted for~~2020. We currently expect to limit our onshore capital expenditures to the completion of the ~~four previously drilled~~salt water disposal well and related infrastructure in West Texas ~~wells.~~($3.7 million), limited workovers ($3.3 million) which are intended to increase production and cashflow, and required onshore plugging and abandonment activity ($0.7 million). We expect ~~to bring these wells on production during~~that our only offshore capital expenditures will be the Iron Flea exploratory well, which was spud in late May 2020 and resulted in a dry hole. During the ~~third and fourth quarters. If~~three months ended March 31, 2020, we ~~are able to refinance and/or replace our Credit Facility, we~~paid a $7.1 million deposit for the turnkey drilling of the Iron Flea prospect, as explained above.

We believe that our internally generated cash ~~flow and proceeds from the sale of non-core assets,~~flows, combined with availability under ~~a new credit facility~~the Credit Agreement (as defined below), will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve ~~months. If~~months; however, should our results of operations be less than expected, or we ~~are not able~~experience additional reductions in our borrowing base, we may need to ~~refinance~~pursue additional sources of liquidity such as monetization of a portion of our hedge portfolio or access the debt and equity markets, as available, to finance any necessary capital development and/or ~~replace~~repay excess borrowings under our Credit ~~Facility,~~Agreement, but there ~~is substantial doubt about~~can be no assurance such incremental financing will be available to us or not result in dilution of our ~~ability~~stockholders or increase our debt service costs. The COVID-19 pandemic and the ongoing disruptions to the global energy markets have negatively impacted, and are expected to continue to negatively impact, cash flows from operating activities. In order to mitigate these effects, we have implemented certain cost cutting measures, such as ~~a going concern. See “Pursuit~~suspending our onshore drilling program for the remainder of ~~Refinancing and Other Liquidity-Enhancing Initiatives”.~~2020.

Cash From Operating Activities

Cash flows ~~provided by~~used in operating activities were approximately ~~$14.9~~$0.2 million ~~in cash~~ for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 compared to ~~$13.3~~$0.1 million ~~provided by~~used in operating activities for the same period in ~~2018.~~2019. Included in the 2020 activity is $7.1 million in a deposit related to an escrow account set up for the drilling of the exploratory Iron Flea offshore well, which will be reclassed to expense in the second quarter of 2020 due to the well being unsuccessful. The table below provides additional detail of cash flows from operating activities for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and ~~2018:~~2019:


	Six Months Ended June 30,
	2019		2018
	(in thousands)

					Three Months Ended March 31,
					2020		2019
					(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	5,902	$	11,902	$	12,300	$	4,525
Changes in operating assets and liabilities		8,996		1,361		(12,548)		(4,664)
Net cash provided by operating activities	$	14,898	$	13,263
Net cash used in operating activities					$	(248)	$	(139)

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Credit Agreement

~~Credit Facility~~

~~Our $500 million secured~~On September 17, 2019, we entered into a new revolving credit ~~facility~~agreement with ~~Royal~~JPMorgan Chase Bank ~~of Canada and other lenders~~ (the “Credit ~~Facility”~~Agreement”), ~~currently matures October~~which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, ~~2019.~~ 2019, in conjunction with the closing of the Will Energy and White Star property acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base was $145 million as of March 31, 2020. The borrowing base is subject to semi-annual redeterminations and may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The semi-annual redeterminations will occur on May 1^st and November 1^st of each year. On June ~~17, 2019, the Company~~9, 2020, we entered into the ~~Seventh~~Second Amendment to the Credit ~~Facility~~Agreement (the ~~“Seventh~~“Second Amendment”). The ~~Seventh~~Second Amendment redetermined the borrowing base at ~~$85~~$95 million pursuant to the regularly scheduled redetermination process, ~~with a current availability limit~~which was in excess of ~~$75 million. As~~borrowings outstanding. The Second Amendment also provides for, among other things, further $10 million automatic reductions in our borrowing base on each of June 30, ~~2019,~~2020 and September 30, 2020. Should borrowings outstanding exceed the reduced borrowing base on the dates of those stepdowns in the borrowing base, we would need to repay any excess within a short period of time through additional sources of liquidity, such as monetization of a portion of our hedge portfolio or the debt or equity capital markets, as available. Although the Company does not expect to have borrowings in excess of the reduced borrowing bases on each of June 30 and September 30, 2020, there can be no assurance that such sources of capital will be available to us. Please read Part II, Item 1A, “Risk Factors.” The Credit Agreement matures on September 17, 2024. As of March 31, 2020, the borrowing availability under the Credit ~~Facility~~Agreement was $13.1 million. The Seventh Amendment also set the next borrowing base redetermination to August 1, 2019. The borrowing base under the Credit Facility effective August 1, 2019 has not yet been determined. If the borrowing base is reduced, we would further minimize our drilling program capital expenditures and repay any borrowings required under the Credit Facility, which could necessitate seeking additional sources of financing to comply with any repayment requirements under the Credit Facility.$60.4 million..

The Credit ~~Facility~~Agreement contains customary and typical restrictive ~~covenants which, among other things, require~~covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit ~~Facility.~~Agreement. The ~~Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination~~Second Amendment includes a waiver of the ~~facility. Events~~Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment provides, among other things, the increase in the Applicable Margin grid on borrowings outstanding by 50 basis points, the implementation of ~~default include, but are not limited~~an accounts payable aging reporting covenant, and the implementation of typical anti-cash hoarding provisions and a cash sweep requirement, in certain circumstances, with respect to ~~audited financial statements that include~~ a ~~going concern qualification, payment defaults, breach~~consolidated cash balance in excess of ~~certain covenants including the current ratio covenant, bankruptcy, insolvency or change of control events.~~$5.0 million. As of ~~June 30, 2019,~~March 31, 2020, we were in compliance with all ~~but the Current Ratio covenant~~financial covenants under the Credit ~~Facility, and we obtained a waiver for such non-compliance effective June 30, 2019.~~Agreement.

~~Pursuit of Refinancing and Other Liquidity-Enhancing Initiatives~~

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

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

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

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

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our ~~2018~~2019 Form 10-K.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies.”

Off Balance Sheet Arrangements

We may enter into ~~off-balance~~off balance sheet arrangements that can give rise to off-balance sheet obligations. As of ~~June 30, 2019, we have no off-balance~~March 31, 2020, our off balance sheet arrangements ~~that are reasonably likely to materially affect~~consist of delay rentals, surface damage payments and rental payments associated with salt water disposal contracts, as discussed in our ~~liquidity or availability of or requirements for capital resources.~~ 2019 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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Our management, with the participation of our President and Chief Executive Officer and our Chief Financial and Accounting Officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of ~~June 30, 2019.~~March 31, 2020. Based upon that evaluation, our President and Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of ~~June 30, 2019,~~March 31, 2020, 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

~~Table of Contents~~

management, including our President and Chief Executive Officer and our Chief Financial and Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

~~There were no changes~~The Company is in the ~~Company’s~~process of integrating Will Energy’s and White Star’s internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. There was no change in our internal control over financial reporting ~~that occurred~~ during the ~~three months~~fiscal quarter ended ~~June 30, 2019~~March 31, 2020 that ~~have~~ materially affected, or ~~are~~is reasonably likely to materially affect, ~~the Company’s~~our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Item 1. Note 1211 to our Financial Statements – “Commitments and Contingencies.”

Item 1A.Risk Factors

~~Item 1A.Risk Factors~~

Except as set forth below, there have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our ~~Annual Report~~2019 Form 10-K.

The COVID-19 pandemic has adversely affected our business, and the ultimate effect on ~~Form 10-K~~our business, financial position, results of operations, and/or cash flows will depend on future developments, which are highly uncertain and cannot be predicted.

The COVID-19 pandemic and the actions by governments, businesses, and individuals in response to the pandemic have caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the ~~year ended December 31, 2018.~~

~~Our bylaws provide, subject~~first week of March 2020, negatively affecting our cash flow, liquidity and financial position. These events have worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to ~~limited exceptions, that~~reach an agreement over proposed oil production cuts. While OPEC+ reached a tentative agreement to cut oil production in April 2020, the announcement of the tentative agreement did not result in increased commodity prices, and those production cuts, if effected, may not offset near-term demand loss attributable to the COVID-19 pandemic and the related economic slowdown. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States ~~District Court for~~resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the ~~Southern District~~second quarter of ~~Texas~~2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when, or to what extent, oil prices will beimprove and stabilize.

The COVID-19 pandemic is rapidly evolving, and the ~~sole~~ultimate impact of this pandemic is highly uncertain and ~~exclusive forum for certain stockholder litigation matters, which could limit~~subject to change. The extent of the impact of the COVID-19 pandemic on our ~~stockholders’~~operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand, the availability of personnel, equipment, and services critical to our ability to ~~obtain a favorable judicial forum for disputes with us~~operate our properties, and how quickly, and to what extent, normal economic and operating conditions can resume. The COVID-19 pandemic may also precipitate or ~~our directors, officers, employees or stockholders.~~

~~Our bylaws provide, subject to limited exceptions, that unless we consent to~~intensify the selection of an alternative forum, the United States District Court for the Southern District of Texas or, if such court lacks jurisdiction, the state district court of Harris County, Texas, shall, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding broughtrisks described in the ~~name or right~~risk factors disclosed in our 2019 Form 10-K.

The reduction in the borrowing base under our Credit Agreement, and any further reductions as a result of the Company or on its behalf, (ii) action asserting a claim for breach of a fiduciary duty owed by any director, officer, employee or other agent of the Company to the Company or the Company’s stockholders, (iii) action asserting a claim arising pursuant to any provision of the Texas Business Organizations Code (the “TBOC”), or our certificate of incorporation or bylaws, or (iv) action asserting a claim governed by the internal affairs doctrine.

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

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

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

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

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

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

Table of Contents

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

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

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

~~Certain antitakeover provisions may affect your rights as a shareholder.~~

Our articles of incorporation authorize our board of directors to set the terms of and issue preferred stock without shareholder approval. Our board of directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our revolving credit facility and our indentures governing our senior notes and our outstanding preferred stock contain terms that may restrict our ability to enter into change of control transactions, including requirements to repayliquidity are borrowings under our ~~revolving credit facility,~~Credit Agreement and cash from operations. The borrowing base under our Credit Agreement is subject to ~~offer~~semi-annual redeterminations which occur on May 1st and November 1st of each year. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to ~~repurchase senior notes~~be outstanding under our Credit Agreement. The borrowing base depends on, among other things, projected revenues from, and to offer to redeem our preferred stock in either event upon a change of control, as determined under the relevant documents relating to such obligations. These provisions, along with specified provisionsasset values of, the ~~TBOC~~oil and natural gas properties securing our ~~articles~~loan, many of ~~incorporation~~which factors are beyond our control. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment reduced the borrowing base from $145 million to $95 million pursuant to the regularly scheduled redetermination process and ~~bylaws,~~provided for further $10 million automatic borrowing base reductions on each of June 30, 2020 and September 30, 2020. As a result of these reductions, we expect to have limited availability under our Credit Agreement, which will impact our readily available access to financing for our capital expenditures.

Should a determination be made to lower the borrowing base to a level less than our outstanding indebtedness thereunder on the date of such reduction, the excess indebtedness (i.e a “deficiency”) would exist that the Company would be required to repay, depending on certain scenarios, either immediately or over a period of six months. Should such a determination be made that creates a deficiency, we may ~~discourage~~be required to obtain additional capital from monetizing hedges or ~~impede transactions involving actual~~accessing the capital markets. There is no assurance, however, that we will be able to do so on acceptable terms, if at all. If we are unable to obtain new capital on acceptable terms, we may be unable to operate our producing properties, recommence or ~~potential changes in~~implement our ~~control, including transactions that~~respective drilling and development plan, make acquisitions or otherwise ~~could involve payment~~carry out business plans, which would have a material adverse effect on our financial condition and results of ~~a premium over prevailing market prices to holders of our common stock.~~operations.

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

The Company withheld the following shares from employees during the ~~three months~~quarter ended ~~June 30, 2019~~March 31, 2020 for the payment of taxes due on shares of restricted stock that vested and were issued under its stock-based compensation plans:

Total Number of Shares

Approximate Dollar Value

Total Number of

Average Price

Purchased as Part of

of Shares that May Yet

Period

Shares Withheld

Per Share

Publicly Announced Program


be Purchased Under Program

April 2019

14,862

$
3.12

—

$
—

May 2019

1,271

$
2.94

—

$
—

June 2019

—

$
—

—

$
—

Total

16,133

$
3.11

—

$
31.8 million (1)



				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 2020	22,972	$	3.63	—	$	—
February 2020	—	$	—	—	$	—
March 2020	26,502	$	2.77	—	$	—
Total	49,474	$	3.17	—	$	31.8 million ⁽¹⁾

(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~~No shares were purchased for the ~~sixth amendment to~~quarter ended March 31, 2020. As of March 31, 2020, the Company has $31.8 million available under its share repurchase program, however, those repurchases could be limited under restrictions in the Company’s Credit ~~Facility, share repurchases under this plan have been suspended.~~

Agreement.

Item 3. Defaults upon Senior Securities

None.

~~Table of Contents~~

Item 4. Mine Safety Disclosures

Not applicable.

Item 5.Other Information

~~Item 5.Other Information~~

None.

~~None.~~


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Crude oil contracts	$	286	$	(1,123)	$	941	$	(1,711)

									Three Months Ended March 31,
									2020		2019
Oil contracts									$	2,797	$	655
Natural gas contracts		211		305		324		380		2,511		113
Realized gain (loss)	$	497	$	(818)	$	1,265	$	(1,331)

Crude oil contracts	$	365	$	(1,311)	$	(3,077)	$	(1,594)
Realized gain									$	5,308	$	768

Oil contracts									$	40,727	$	(3,443)
Natural gas contracts		1,203		(481)		999		(717)		664		(203)
Unrealized gain (loss)	$	1,568	$	(1,792)	$	(2,078)	$	(2,311)	$	41,391	$	(3,646)
Gain (loss) on derivatives, net	$	2,065	$	(2,610)	$	(813)	$	(3,642)	$	46,699	$	(2,878)

Exhibit Number		Description
~~2.1~~	3.1	Agreement and Plan of Merger dated as of April 26, 2019, by and between Contango Oil & Gas Company and MCF Merger Sub Corp (filed as Exhibit 2.1 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
~~3.1~~		Amended and Restated Certificate of Formation of Contango Oil & Gas Company (filed as Exhibit 3.3 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.2		Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
10.1		Separation Agreement and General Release by Contango Oil & Gas Company and Tommy H. Atkins dated April 16, 2019 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 16, 2019, as filed with the Securities and Exchange Commission on April 17, 2019 and incorporated by reference herein).
~~10.2~~		~~Seventh~~Second Amendment to Credit Agreement, dated ~~as of~~ June ~~17, 2019~~9, 2020, by and among Contango Oil & Gas Company, ~~as Borrower, Royal~~JPMorgan Chase Bank, ~~of Canada,~~N.A., as Administrative Agent, and the Lenders Signatory hereto (filed as Exhibit 10.1 to the Company’s ~~Current~~ Report on Form 8-K dated June ~~17, 2019,~~15, 2020, as filed with the Securities and Exchange Commission on June ~~18, 2019~~15, 2020 and incorporated by reference herein)..
31.1		Certification of Chief Executive Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
31.2		Certification of Chief Financial Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
101		Interactive Data Files †


		CONTANGO OIL & GAS COMPANY


Date: ~~August 8, 2019~~June 22, 2020	By:	~~/s/~~/s/ WILKIE S. COLYER
		Wilkie S. Colyer
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: ~~August 8, 2019~~June 22, 2020	By:	~~/s/~~/s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)



Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Natural Gas	July 2019	Swap	600,000	Mmbtus	$	2.75			(1)	$	278
Natural Gas	Aug 2019 - Oct 2019	Swap	100,000	Mmbtus	$	2.75			(1)	$	136
Natural Gas	Nov 2019 - Dec 2019	Swap	500,000	Mmbtus	$	2.75			(1)	$	267

Oil	July 2019 - Dec 2019	Collar	7,000	Bbls	$	50.00	-	58.00	(2)	$	(237)
Oil	July 2019 - Dec 2019	Collar	4,000	Bbls	$	52.00	-	59.45	(3)	$	(33)

Oil	July 2019	Swap	6,000	Bbls	$	66.10			(3)	$	46

Oil	July 2019	Swap	12,000	Bbls	$	72.10			(3)	$	163
Oil	Aug 2019 - Oct 2019	Swap	9,000	Bbls	$	72.10			(3)	$	370
Oil	Nov 2019 - Dec 2019	Swap	12,000	Bbls	$	72.10			(3)	$	340

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

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

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

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

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

		Total net fair value of derivative instruments								$	2,185


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

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

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

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


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



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

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