10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2019

OR

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	76-0466193 (I.R.S. Employer Identification No.)
801 Louisiana, Suite 700 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (Registrant’s telephone number, including area code): (713) 780-9494 Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbol	Name of each exchange on which registered
Common stock, par value $0.01 per share	GDP	NYSE American

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

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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  ☒

Indicate by check mark whether the Registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ☒    No  ☐

The Registrant had 12,303,718 shares of common stock outstanding on August 7, 2019.

1

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

TABLE OF CONTENTS

		Page
PART I	FINANCIAL INFORMATION	3
ITEM 1	FINANCIAL STATEMENTS	3
	Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 (unaudited)	3
	Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018 (unaudited)	4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018 (unaudited)	5
	Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2019 and 2018 (unaudited)	6
	Notes to Unaudited Consolidated Financial Statements	7
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 4	CONTROLS AND PROCEDURES	31
PART II	OTHER INFORMATION	32
ITEM 1	LEGAL PROCEEDINGS	32
ITEM 1A	RISK FACTORS	32
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	32
ITEM 6	EXHIBITS	33

2

PART I – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

(Unaudited)

	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,669		$	4,068
Accounts receivable, trade and other, net of allowance		2,660			744
Accrued oil and natural gas revenue		15,869			14,464
Fair value of oil and natural gas derivatives		11,421			803
Inventory		584			596
Prepaid expenses and other		374			533
Total current assets		32,577			21,208
PROPERTY AND EQUIPMENT:
Unevaluated properties		105			180
Oil and natural gas properties (full cost method)		259,247			206,097
Furniture, fixtures and equipment and other capital assets		4,359			1,360
		263,711			207,637
Less: Accumulated depletion, depreciation and amortization		(66,272	)		(42,447	)
Net property and equipment		197,439			165,190
Fair value of oil and natural gas derivatives		719			-
Deferred tax asset		786			786
Other		2,220			580
TOTAL ASSETS	$	233,741		$	187,764
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	35,897		$	25,734
Accrued liabilities		16,044			16,518
Fair value of oil and natural gas derivatives		376			-
Total current liabilities		52,317			42,252
Long term debt, net		94,904			76,820
Accrued abandonment cost		3,963			3,791
Fair value of oil and natural gas derivatives		-			471
Other non-current liabilities		1,523			-
Total liabilities		152,707			123,334
Commitments and contingencies (See Note 9)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding		-			-
Common stock: $0.01 par value, 75,000,000 shares authorized, and 12,302,318 and 12,150,918 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively		123			122
Treasury stock: 46,781 and zero shares as of June 30, 2019 and December 31, 2018, respectively		(543	)		-
Additional paid in capital		79,780			74,861
Accumulated earnings (deficit)		1,674			(10,553	)
Total stockholders’ equity		81,034			64,430
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	233,741		$	187,764

See accompanying notes to consolidated financial statements.

3

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,			Six Months Ended June 30,
	2019			2018			2019			2018
REVENUES:
Oil and natural gas revenues	$	31,886		$	17,784		$	61,032		$	29,627
Other		(2	)		51			(8	)		42
		31,884			17,835			61,024			29,669
OPERATING EXPENSES:
Lease operating expense		2,978			2,465			6,313			5,031
Production and other taxes		624			669			1,255			1,309
Transportation and processing		5,754			2,086			10,455			3,398
Depreciation, depletion and amortization		13,299			5,560			23,345			9,012
General and administrative		4,936			4,803			10,246			9,999
Other		(59	)		165			(49	)		165
		27,532			15,748			51,565			28,914
Operating income		4,352			2,087			9,459			755
OTHER INCOME (EXPENSE):
Interest expense		(3,398	)		(2,732	)		(7,055	)		(5,405	)
Interest income and other expense		18			116			24			109
Gain (loss) on commodity derivatives not designated as hedges		12,653			(2,174	)		11,645			(3,155	)
Loss on early extinguishment of debt		(1,846	)		-			(1,846	)		-
		7,427			(4,790	)		2,768			(8,451	)
Reorganization items, net		-			42			-			(289	)
Income (loss) before income taxes		11,779			(2,661	)		12,227			(7,985	)
Income tax benefit		-			-			-			-
Net income (loss)	$	11,779		$	(2,661	)	$	12,227		$	(7,985	)
PER COMMON SHARE
Net income (loss) per common share - basic	$	0.96		$	(0.23	)	$	1.00		$	(0.70	)
Net income (loss) per common share - diluted	$	0.82		$	(0.23	)	$	0.85		$	(0.70	)
Weighted average shares of common stock outstanding - basic		12,211			11,629			12,181			11,424
Weighted average shares of common stock outstanding - diluted		14,581			11,629			14,498			11,424

See accompanying notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,			Six Months Ended June 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	12,227		$	(7,985	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		23,345			9,012
Right of use asset depreciation		626			-
(Gain) loss on commodity derivatives not designated as hedges		(11,645	)		3,155
Net cash received (paid) for settlement of derivative instruments		213			(541	)
Share-based compensation (non-cash)		3,148			3,167
Amortization of finance cost, debt discount, paid in-kind interest and accretion		7,445			5,157
Reorganization items (non-cash), net		-			289
Other		12			218
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		(1,916	)		(598	)
Accrued oil and natural gas revenue		(1,405	)		(2,359	)
Prepaid expenses and other		131			(20	)
Accounts payable		10,163			3,936
Accrued liabilities		(1,091	)		(776	)
Net cash provided by operating activities		41,253			12,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(55,066	)		(53,100	)
Proceeds from sale of assets		1,284			26,920
Net cash used in investing activities		(53,782	)		(26,180	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(49,500	)		(16,723	)
Proceeds from bank borrowings		106,900			6,000
Repayment of Convertible Second Lien Notes		(56,728	)		-
Proceeds from New 2L Notes		12,000			-
Issuance cost, net		(2,000	)		(10	)
Purchase of treasury stock and other		(542	)		(5	)
Net cash provided by (used in) financing activities		10,130			(10,738	)
Decrease in cash and cash equivalents		(2,399	)		(24,263	)
Cash and cash equivalents, beginning of period		4,068			25,992
Cash and cash equivalents, end of period	$	1,669		$	1,729
Supplemental disclosures of cash flow information:
Cash paid for reorganization items, net	$	-		$	543
Cash paid for interest	$	1,681		$	249
Increase (decrease) in non-cash capital expenditures	$	(1,019	)	$	(2,805	)

See accompanying notes to consolidated financial statements.

5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

(In thousands)

(Unaudited)

	Preferred Stock				Common Stock				Additional Paid-in			Treasury Stock						Accumulated			Total Stockholders’
	Shares		Value		Shares		Value		Capital			Shares			Value			Earnings (Deficit)			Equity
Balance at December 31, 2017		-	$	-		10,771	$	108	$	68,446			-		$	-		$	(12,303	)	$	56,251
Net loss		-		-		-		-		-			-			-			(5,324	)		(5,324	)
Share-based compensation		-		-		-		-		1,776			-			-			-			1,776
Restricted stock vesting & other		-		-		203		2		2,224			(75	)		(827	)		-			1,399
Convertible Second Lien Notes warrant exercises		-		-		589		6		(6	)		-			-			-			-
Issuance cost		-		-		-		-		(34	)		-			-			-			(34	)
Balance at March 31, 2018		-		-		11,563		116		72,406			(75	)		(827	)		(17,627	)		54,068
Net loss		-		-		-		-		-			-			-			(2,661	)		(2,661	)
Share-based compensation		-		-		-		-		1,758			-			-			-			1,758
Restricted stock vesting & other		-		-		1		-		-			(1	)		(5	)		-			(5	)
Convertible Second Lien Notes warrant exercises		-		-		273		3		1			-			-			-			4
Issuance cost		-		-		-		-		(30	)		-			-			-			(30	)
Balance at June 30, 2018		-	$	-		11,837	$	119	$	74,135			(76	)	$	(832	)	$	(20,288	)	$	53,134
Balance at December 31, 2018		-	$	-		12,151	$	122	$	74,861			-		$	-		$	(10,553	)	$	64,430
Net income		-		-		-		-		-			-			-			448			448
Share-based compensation		-		-		-		-		1,745			-			-			-			1,745
Treasury stock activity		-		-		1		-		-			-			(5	)		-			(5	)
Balance at March 31, 2019		-		-		12,152		122		76,606			-			(5	)		(10,105	)		66,618
Net income		-		-		-		-		-			-			-			11,779			11,779
Share-based compensation		-		-		-		-		1,765			-			-			-			1,765
New 2L Notes conversion		-		-		-		-		1,429			-			-			-			1,429
Convertible Second Lien Notes warrant exercises		-		-		150		1		(20	)		-			-			-			(19	)
Treasury stock activity		-		-		-		-		-			47			(538	)		-			(538	)
Balance at June 30, 2019		-	$	-		12,302	$	123	$	79,780			47		$	(543	)	$	1,674		$	81,034

See accompanying notes to consolidated financial statements.

6

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the “Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.

Basis of Presentation

The consolidated financial statements of the Company included in this Quarterly Report on Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and accordingly, certain information normally included in financial statements prepared in accordance with United States Generally Accepted Accounting Principles (“US GAAP”) has been condensed or omitted. This information should be read in conjunction with our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2018. Operating results for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for the full year or for any interim period.

Principles of Consolidation—The consolidated financial statements include the financial statements of the Company and the Subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

Use of Estimates— Our management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.

Cash and Cash Equivalents—Cash and cash equivalents includes cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at the date of purchase.

Accounts Payable—Accounts payable consisted of the following amounts as of June 30, 2019 and December 31, 2018:

(In thousands)	June 30, 2019		December 31, 2018
Trade payables	$	14,317	$	8,633
Revenue payables		21,057		16,665
Prepayments from partners		293		132
Miscellaneous payables		230		304
Total Accounts payable	$	35,897	$	25,734

7

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Accrued Liabilities—Accrued liabilities consisted of the following amounts as of June 30, 2019 and December 31, 2018:

(In thousands)	June 30, 2019		December 31, 2018
Accrued capital expenditures	$	7,067	$	8,086
Accrued lease operating expense		936		1,100
Accrued production and other taxes		704		338
Accrued transportation and gathering		2,860		1,888
Accrued performance bonus		1,943		3,420
Accrued interest		216		443
Accrued office lease		1,359		598
Accrued general and administrative expense and other		959		645
Total Accrued liabilities	$	16,044	$	16,518

Inventory—Inventory consists of casing and tubulars that are expected to be used in our capital drilling program. Inventory is carried on the Consolidated Balance Sheets at the lower of cost or market.

Property and Equipment—Under US GAAP, two acceptable methods of accounting for oil and natural gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the computation of depreciation, depletion and amortization (“DD&A”) expense and the assessment of impairment of oil and natural gas properties. We have elected to adopt the Full Cost Method of accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method better reflects the true economics of exploring for and developing our oil and gas reserves.

Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, but do not include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and natural gas properties and thereby subject to DD&A and the full cost ceiling test. For the three months ended June 30, 2019 and 2018, we transferred $0.1 million and $0.3 million, respectively, from unevaluated properties to proved oil and natural gas properties. For the six months ended June 30, 2019 and 2018, we transferred $0.2 million and $0.4 million, respectively, from unevaluated properties to proved oil and natural gas properties. Our sales of oil and natural gas properties are accounted for as adjustments to net proved oil and natural gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods' production also converted to Mcfe to arrive at the periods' DD&A expense.

Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from three to five years.

Full Cost Ceiling Test—The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and natural gas properties, net of related deferred taxes. This comparison is referred to as a “ceiling test”. If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a 12-month average pricing assumption.

There were no Full Cost Ceiling Test write-downs for the three or six months ended June 30, 2019 or 2018.

8

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurement—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of non-performance, which includes, among other things, our credit risk.

We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into three levels (levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels and our corresponding instruments classified by level are further described below:

• Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;

• Level 2 Inputs— quotes that are derived principally from or corroborated by observable market data. Included in this level are our 2017 Senior Credit Facility and 2019 Senior Credit Facility (both as defined below) and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counter-parties; and

• Level 3 Inputs— unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this level would be our initial measurement of asset retirement obligations.

As of June 30, 2019 and December 31, 2018, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

Asset Retirement Obligations—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and natural gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations. See Note 3.

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Revenue Recognition—Oil and natural gas revenues are generally recognized upon delivery of our produced oil and natural gas volumes to our customers. We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. As ofJune 30, 2019and December 31, 2018, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted. See Note 2.

Derivative Instruments—We use derivative instruments such as swaps, collars, futures, forwards and options for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counter-party for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All of our realized gain or losses on our derivative contracts are the result of cash settlements. We have not designated any of our derivative contracts as hedges; accordingly, changes in fair value are reflected in earnings. See Note 8.

9

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes—We account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 7.

Net Income or Net Loss Per Common Share—Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted-average shares of common stock outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted average shares of common stock outstanding during the period, plus the effects of potentially dilutive restricted stock calculated using the treasury stock method and the potential dilutive effect of the conversion of convertible securities, such as warrants and convertible notes, into shares of our common stock. See Note 6.

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the related environmental liability. See Note 9.

Share-Based Compensation—We account for our share-based transactions using the fair value as of the grant date and recognize compensation expense over the requisite service period.

Guarantee—As of June 30, 2019, Goodrich Petroleum Company LLC, the wholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our New 2L Notes (as defined below).

Debt Issuance Cost—The Company records debt issuance costs associated with its New 2L Notes (and previously with its Convertible Second Lien Notes, both as defined below) as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the life of the respective notes. Debt issuance costs associated with our revolving credit facility debt are recorded in other assets in our Consolidated Balance Sheets, which is amortized straight-line over the life of such debt.

New Accounting Pronouncements

On August 28, 2018, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“Topic 820”). The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic 820 including the removal, modification and addition of certain disclosure requirements. For all entities, the amendments in this ASU are effective for fiscal periods beginning after December 15, 2019, including interim periods therein. We are evaluating the expected impact these amendments will have on our consolidated financial statements.

10

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2—Revenue Recognition

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and the series of related ASU's that followed under Accounting Standards Codification (“ASC”) Topic 606 (collectively, “Topic 606”).Topic 606 did not change our pattern of timing of revenue recognition. Under Topic 606, revenue is generally recognized upon delivery of our produced oil and natural gas volumes to our customers. Our customer sales contracts include oil and natural gas sales. Under Topic 606, each unit (Mcf or barrel) of commodity product represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of our contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced natural gas volumes passes to our customers at specific metered points indicated in our natural gas contracts. Similarly, control of our produced oil volumes passes to our customers when the oil is measured either by a trucking oil ticket or by a meter when entering an oil pipeline. The Company has no control over the commodities after those points and the measurement at those points dictates the amount on which the customer's payment is based. Our oil and natural gas revenue streams include volumes burdened by royalty and non-operated working interests. Our revenues are recorded and presented on our financial statements net of the royalty and non-operated working interests. Our revenue stream does not include any payments for services or ancillary items other than sale of oil and natural gas.

We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. As of June 30, 2019 and December 31, 2018, receivables from contracts with customers were $15.9 million and $14.5 million, respectively.

The following table presents our revenues disaggregated by revenue source and by operated and non-operated properties for the three and six months ended June 30, 2019 and 2018:

	Three Months Ended June 30, 2019								Six Months Ended June 30, 2019
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	2,805	$	25,163	$	-	$	27,968	$	5,516	$	45,337	$	-	$	50,853
Non-operated		139		3,775		4		3,918		214		9,957		8		10,179
Total oil and natural gas revenues	$	2,944	$	28,938	$	4	$	31,886	$	5,730	$	55,294	$	8	$	61,032

	Three Months Ended June 30, 2018								Six Months Ended June 30, 2018
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	3,835	$	10,900	$	-	$	14,735	$	7,634	$	16,701	$	-	$	24,335
Non-operated		133		2,912		4		3,049		276		5,008		8		5,292
Total oil and natural gas revenues	$	3,968	$	13,812	$	4	$	17,784	$	7,910	$	21,709	$	8	$	29,627

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the six months ended June 30, 2019 is as follows (in thousands):

	Six Months Ended June 30, 2019
Beginning balance as of December 31, 2018	$	3,791
Liabilities incurred		82
Liabilities settled		(3	)
Dispositions		(53	)
Accretion expense		146
Ending balance as of June 30, 2019	$	3,963
Current liability	$	-
Long term liability	$	3,963

NOTE 4—Debt

Debt consisted of the following balances as of June 30, 2019 and December 31, 2018 (in thousands):

	June 30, 2019				December 31, 2018
	Principal		Carrying Amount		Principal		Carrying Amount
2017 Senior Credit Facility	$	-	$	-	$	27,000	$	27,000
2019 Senior Credit Facility		84,400		84,400		-		-
Convertible Second Lien Notes (1)		-		-		53,691		49,820
New 2L Notes (2)		12,135		10,504		-		-
Total debt	$	96,535	$	94,904	$	80,691	$	76,820

(1) The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019.

(2) The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2021. The principal included $0.1 million of accrued interest to be paid in-kind as of June 30, 2019. The carrying value included $1.4 million of unamortized debt discount as of June 30, 2019.

12

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the total interest expense for the three and six months ended June 30, 2019 and 2018 including contractual interest expense, amortization of debt discount and financing costs (amounts in thousands, except effective interest rates):

	Three Months Ended June 30, 2019					Three Months Ended June 30, 2018					Six Months Ended June 30, 2019					Six Months Ended June 30, 2018
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
2017 Senior Credit Facility	$	364		8.2	%	$	75	*			$	872		7.2	%	$	248		7.8	%
2019 Senior Credit Facility		695		5.9	%		-		-			695		5.9	%		-		-
Convertible Second Lien Notes (1)		2,155		23.9	%		2,657		24.7	%		5,304		24.1	%		5,157		24.8	%
New 2L Notes (2)		184		20.5	%		-		-			184		20.5	%		-		-
Total interest expense	$	3,398				$	2,732				$	7,055				$	5,405

(1) The Convertible Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 23.9% and 24.1%, respectively, for the three and six months ended June 30, 2019 and 24.7% and 24.8%, respectively, for the three and six months ended June 30, 2018. Interest expense for the three months ended June 30, 2019 included $0.9 million of debt discount amortization and $1.2 million of paid in-kind interest, and interest expense for the three months ended June 30, 2018 included $1.0 million of debt discount amortization and $1.6 million of paid in-kind interest. Interest expense for the six months ended June 30, 2019 included $2.3 million of debt discount amortization and $3.0 million of paid in-kind interest, and interest expense for the six months ended June 30, 2018 included $1.8 million of debt discount amortization and $3.2 million of paid in-kind interest.

(2) The New 2L Notes have a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 20.5% for the three and six months ended June 30, 2019. Interest expense for the three and six months ended June 30, 2019 included less than $0.1 million of debt discount amortization and $0.1 million of accrued interest to be paid in-kind.

* - Not meaningful due to the timing of borrowings during the three months ended June 30, 2018.

2017 Senior Credit Facility

On October 17, 2017, the Company entered into the Amended and Restated Senior Secured Revolving Credit Agreement (as amended, the “2017 Credit Agreement”) with the Subsidiary, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are party thereto, which provided for revolving loans of up to the borrowing base then in effect (as amended, the “2017 Senior Credit Facility”). The 2017 Senior Credit Facility was set to mature on (a) October 17, 2021 or (b) December 30, 2019, if the Convertible Second Lien Notes had not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 30, 2019. The maximum credit amount under the 2017 Senior Credit Facility when it was paid off in full on May 14, 2019 was $250.0 million with a borrowing base of $75.0 million.

All amounts outstanding under the 2017 Senior Credit Facility bore interest at a rate per annum equal to, at the Company's option, either (i) the alternative base rate plus an applicable margin ranging from 1.75% to 2.75%, depending on the percentage of the borrowing base that was utilized, or (ii) adjusted LIBOR plus an applicable margin ranging from 2.75% to 3.75%, depending on the percentage of the borrowing base that was utilized. Undrawn amounts under the 2017 Senior Credit Facility were subject to a 0.50% commitment fee.

The obligations under the 2017 Credit Agreement were secured by a first lien security interest in substantially all of the assets of the Company and the Subsidiary.

On May 14, 2019, the 2017 Senior Credit Facility was paid off in full and amended, restated and refinanced into the 2019 Senior Credit Facility. In connection with the refinancing, we recorded a $0.2 million loss on early extinguishment of debt related to the remaining unamortized debt issuance costs.

13

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2019 Senior Credit Facility

On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amends, restates and refinances the obligations under the 2017 Credit Agreement.

The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) the date that is 180 days prior to the “Maturity Date” as defined in the New 2L Notes Indenture (as defined below) as in effect on the date of issuance of the New 2L Notes if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by such date. The maximum credit amount under the 2019 Senior Credit Facility is currently $500 million with an initial borrowing base of $115 million. The borrowing base is scheduled to be redetermined in August of 2019 and thereafter in March and September of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

All amounts outstanding under the 2019 Senior Credit Facility bear interest at a rate per annum equal to, at the Company’s option, either (i) the alternative base rate plus an applicable margin ranging from 1.50% to 2.50%, depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin from 2.50% to 3.50%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 2019 Senior Credit Facility are subject to a commitment fee ranging from 0.375% to 0.50%, depending on the percentage of the borrowing base that is utilized. To the extent that a payment default exists and is continuing, all amounts outstanding under the 2019 Senior Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto.

The obligations under the 2019 Credit Agreement are guaranteed by the Company and secured by a first lien security interest in substantially all of the assets of the Company and the Borrower.

The 2019 Credit Agreement contains certain customary representations and warranties, affirmative and negative covenants and events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the 2019 Senior Credit Facility to be immediately due and payable.

The 2019 Credit Agreement also contains certain financial covenants, including the maintenance of (i) a ratio of Net Funded Debt to EBITDAX not to exceed 4.00 to 1.00 as of the last day of any fiscal quarter, (ii) a current ratio (based on the ratio of current assets to current liabilities as defined in the 2019 Credit Agreement) not to be less than 1.00 to 1.00 and (iii) until no New 2L Notes remain outstanding, a ratio of Total Proved PV-10 attributable to the Company’s and Borrower’s Proved Reserves to Total Secured Debt (net of any Unrestricted Cash not to exceed $10 million) not to be less than 1.50 to 1.00 and minimum liquidity requirements.

14

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

On May 14, 2019, the Company utilized borrowings under the 2019 Senior Credit Facility to refinance its obligations under the 2017 Senior Credit Facility and to fund the Redemption (as defined below) of the Convertible Second Lien Notes.

As of June 30, 2019, the Company had a borrowing base of $115.0 million with $84.4 million outstanding. The Company also had $2.1 million of unamortized debt issuance costs recorded as of June 30, 2019 related to the 2019 Senior Credit Facility.

As of June 30, 2019, the Company was in compliance with all covenants within the 2019 Senior Credit Facility.

Convertible Second Lien Notes

On October 12, 2016, the Company and the Subsidiary, entered into a purchase agreement with certain investors (collectively, and together with each of their successors and assigns, the “Purchasers”), in connection with the issuance of $40.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible Second Lien Notes”).

The aggregate principal amount of the Convertible Second Lien Notes was convertible at the option of the Purchasers at any time prior to the scheduled maturity date at $21.33 per share representing 1.9 million shares of the Company's common stock, subject to adjustments. At closing, the Purchasers were issued 10-year costless warrants to acquire 2.5 million shares of common stock. Holders of the Convertible Second Lien Notes had a second priority lien on all assets of the Company, and holders of such warrants had a right to appoint two members to our Board of Directors (the “Board”) as long as such warrants were outstanding.

The Convertible Second Lien Notes, as set forth in the agreement, were scheduled to mature on August 30, 2019 or six months after the maturity of our current revolving credit facility but in no event later than March 30, 2020. The Convertible Second Lien Notes bore interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company also had the option under certain circumstances to pay all or any portion of interest in-kind on the then outstanding principal amount of the Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional second lien notes.

Upon issuance of the Convertible Second Lien Notes in October 2016, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion as well as warrants on the debt instrument, we recorded a debt discount of $11.0 million, thereby reducing the $40.0 million carrying value upon issuance to $29.0 million and recorded an equity component of $11.0 million. The debt discount was amortized using the effective interest rate method based upon an original term through August 30, 2019. The Convertible Second Lien Notes were paid off in full on May 29, 2019 for $56.7 million. In connection with the payoff of the Convertible Second Lien Notes, we recorded a $1.6 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs.

15

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Redemption of Convertible Second Lien Notes

On May 14, 2019, the Company satisfied and discharged and called for redemption the Convertible Second Lien Notes by depositing funds equal to the redemption price plus interest on the Company’s approximately $56.7 million aggregate principal amount of outstanding Convertible Second Lien Notes, and such notes were redeemed on May 29, 2019. The Company used borrowings under its 2019 Senior Credit Facility to fund the satisfaction, discharge and redemption of the Convertible Second Lien Notes.

New Convertible Second Lien Notes 

On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company issued to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering occurred on May 31, 2019. Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. Holders of the New 2L Notes have a second priority lien on all assets of the Company.

The New 2L Notes, as set forth in the indenture governing such notes (the “New 2L Notes Indenture”), are scheduled to mature on May 31, 2021. The New 2L Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the New 2L Notes by increasing the principal amount of the outstanding New 2L Notes. 

The New 2L Notes Indenture contains certain covenants pertaining to us and our Subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sales of assets and stock; business activities; transactions with affiliates; and changes of control. The New 2L Notes Indenture also contains a financial covenant which requires the maintenance of a Total Proved Asset Coverage Ratio not to be less than 1.50 to 1.00.

The New 2L Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of New 2L Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be $21.33, subject to certain adjustments as described in the New 2L Notes Indenture. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the New 2L Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the New 2L Notes with cash is subject to the terms of the 2019 Senior Credit Agreement.

The New 2L Notes were issued and sold to the New 2L Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereunder. The New 2L Notes Purchasers may only resell the New 2L Notes only to qualified institutional buyers in accordance with Rule 144A under the Securities Act and to certain persons outside the United States in accordance with Regulation S under the Securities Act. The New 2L Notes have not been registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws.

Upon issuance of the New 2L Notes on May 31, 2019, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $1.4 million, thereby reducing the $12.0 million carrying value upon issuance to $10.6 million and recorded an equity component of $1.4 million. The equity component was valued using a binomial model. The debt discount is amortized using the effective interest rate method based upon an original term through May 31, 2021.

As of June 30, 2019, $1.4 million of debt discount and $0.2 million of debt issuance costs remained to be amortized on the New 2L Notes.

As of June 30, 2019, the Company was in compliance with all covenants within the New 2L Notes Indenture.

16

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5—Equity

During the three and six months ended June 30, 2019, 150,000 of the 10-year costless warrants associated with the Convertible Second Lien Notes were exercised. The Company received cash for the one cent par value for the issuance of the 150,000 common shares. As of June 30, 2019, no such warrants remain un-exercised. The Company did not have a material vesting of its share-based compensation units during the three or six months ended June 30, 2019.

In connection with the issuance of the New 2L Notes, we recorded an equity component of $1.4 million. For further details, see Note 4.

During the three months ended June 30, 2018, certain holders of the 10-year costless warrants associated with the Convertible Second Lien Notes exercised 273,437 warrants for the issuance of an equal amount of our one cent par value common stock. The Company received cash for the one cent par value for the issuance of 273,437 common shares. During the six months ended June 30, 2018, certain holders of the 10-year costless warrants associated with the Convertible Second Lien Notes exercised 862,812 warrants for the issuance of an equal amount of our one cent par value common stock. The Company received cash for the one cent par value for the issuance of 315,937 common shares. As of June 30, 2018, 207,500 of such warrants remain un-exercised. The Company did not have a material vesting of its share-based compensation units during the three or six months ended June 30, 2018.

NOTE 6—Net Income (Loss) Per Common Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted net income (loss) per common share for the three and six months ended June 30, 2019 and 2018. The Company used the treasury stock method in determining the effects of potentially dilutive restricted stock. The following table sets forth information related to the computations of basic and diluted net income (loss) per common share:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(Amounts in thousands, except per share data)
Basic net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Basic net income (loss) per common share	$	0.96	$	(0.23	)	$	1.00	$	(0.70	)
Diluted net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Interest, discount and amortization on New 2L Notes		107		-			107		-
Adjusted net income (loss) per common share	$	11,886	$	(2,661	)	$	12,334	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Common shares issuable upon conversion of the New 2L Notes		569		-			569		-
Common shares issuable upon conversion of warrants of unsecured claim holders		1,282		-			1,282		-
Common shares issuable on assumed conversion of restricted stock (4)		519		-			466		-
Diluted weighted average shares of common stock outstanding		14,581		11,629			14,498		11,424
Diluted net income (loss) per common share (1) (2) (3)	$	0.82	$	(0.23	)	$	0.85	$	(0.70	)
(1) Common shares issuable on assumed conversion of share-based compensation for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. (4)		-		491			-		346
(2) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,875			-		1,875
(3) Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,642			-		1,642

(4) Common shares issuable on assumed conversion of share-based compensation assumes a payout of the Company's performance share awards at 100% of the initial units granted (or a ratio of one unit to one common share). The range of common stock shares which may be earned ranges from zero to 250% of the initial performance units granted.

17

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7—Income Taxes

We recorded no income tax expense or benefit for either the three or six months ended June 30, 2019 or 2018. We recorded a valuation allowance for our net deferred tax asset at December 31, 2016. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our history of net operating losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. The valuation allowance was $84.1 million as of December 31, 2018, which resulted in a net non-current deferred tax asset of $0.8 million appearing on our statement of financial position. The net $0.8 million deferred tax asset relates to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability. Considering the Company’s taxable income forecasts, our assessment of the realization of our deferred tax assets has not changed, and we continue to maintain a full valuation allowance for our net deferred tax assets as of June 30, 2019 aside from the deferred tax asset related to the AMT credits.

As of June 30, 2019, we have no unrecognized tax benefits. There were no significant changes to our tax position since December 31, 2018.

NOTE 8—Commodity Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices. We are currently not designating our derivative contracts for hedge accounting. All derivative gains and losses are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.

The following table summarizes gains and losses we recognized on our oil and natural gas derivatives for the three and six months ended June 30, 2019 and 2018:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Oil and Natural Gas Derivatives (in thousands)
Gain (loss) on commodity derivatives not designated as hedges, settled	$	1,973	$	(156	)	$	213	$	(541	)
Gain (loss) on commodity derivatives not designated as hedges, not settled		10,680		(2,018	)		11,432		(2,614	)
Total gain (loss) on commodity derivatives not designated as hedges	$	12,653	$	(2,174	)	$	11,645	$	(3,155	)

Commodity Derivative Activity

We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all derivatives are approved by the Hedging Committee of our Board, and reviewed periodically by the Board.

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Decreases in domestic crude oil and natural gas spot prices will have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counter-parties. Neither our counter-parties nor we require any collateral upon entering into derivative contracts. We would have been at risk of losing $12.1 million had SunTrust Bank and RBC Capital Markets been unable to fulfill their obligations as of June 30, 2019.

18

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2019, the open positions on our outstanding commodity derivative contracts, all of which were with SunTrust Bank and RBC Capital Markets, were as follows:

Contract Type	Average Daily Volume		Total Volume		Weighted Average Fixed Price		Fair Value at June 30, 2019 (In thousands)
Oil swaps (Bbls)
2019		300		55,200	$	51.08	$	(376	)
2020		221		80,945	$	59.02		243
2021 (through March 31, 2021)		200		18,000	$	56.58		37
Total oil							$	(96	)
Natural Gas swaps (MMBtu)
2019		100,000		18,400,000	$	2.887	$	9,587
2020		33,344		12,204,000	$	2.756		2,155
2021 (through March 31, 2021)		16,656		1,499,000	$	2.862		118
Total natural gas							$	11,860
Total oil and natural gas							$	11,764

During the second quarter of 2019 we entered into the following contracts with RBC Capital Markets:

Contract Type	Average Daily Volume		Weighted Average Fixed Price		Contract Start Date	Contract Termination
Natural gas swap (MMBtu)		20,090	$	2.677	April 1, 2020	March 31, 2021
Oil swap (Bbls)		217	$	58.57	January 1, 2020	March 31, 2021

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of June 30, 2019 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1—“Description of Business and Significant Accounting Policies” for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.

Description	Level 1		Level 2			Level 3		Total
Fair value of oil and natural gas derivatives - Current Assets	$	-	$	11,421		$	-	$	11,421
Fair value of oil and natural gas derivatives - Non-current Assets		-		719			-		719
Fair value of oil and natural gas derivatives - Current Liabilities		-		(376	)		-		(376	)
Fair value of oil and natural gas derivatives - Non-current Liabilities		-		-			-		-
Total	$	-	$	11,764		$	-	$	11,764

We enter into oil and natural gas derivative contracts under which we have netting arrangements with each counter-party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018:

	June 30, 2019								December 31, 2018
Fair Value of Oil and Natural Gas Derivatives	Gross			Amount		As			Gross			Amount			As
(in thousands)	Amount			Offset		Presented			Amount			Offset			Presented
Fair value of oil and natural gas derivatives - Current Assets	$	11,421		$	-	$	11,421		$	2,893		$	(2,090	)	$	803
Fair value of oil and natural gas derivatives - Non-current Assets		719			-		719			-			-			-
Fair value of oil and natural gas derivatives - Current Liabilities		(376	)		-		(376	)		(2,090	)		2,090			-
Fair value of oil and natural gas derivatives - Non-current Liabilities		-					-			(471	)		-			(471	)
Total	$	11,764		$	-	$	11,764		$	332		$	-		$	332

19

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9—Commitments and Contingencies

We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, would not have been material to our consolidated financial position, results of operations or liquidity for the three and six months ended June 30, 2019 and 2018.

NOTE 10—Leases

We adopted ASU 2016-02, Leases, during the quarter ended March 31, 2019, and we elected the transition relief package of practical expedients. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of 12 months or less are not recorded on our Consolidated Balance Sheets. We lease our corporate office building in Houston, Texas. We recognize lease expense for this lease on a straight-line basis over the lease term. This operating lease is included in furniture, fixtures and equipment and other capital assets, accrued liabilities and other non-current liabilities on our Consolidated Balance Sheets. The operating lease asset and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term. As this lease did not provide an implicit rate, we used a collateralized incremental borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease asset includes any lease payments made but excludes annual operating charges. Operating lease expense is recognized on a straight-line basis over the lease term and reported in general and administrative operating expense on our Consolidated Statements of Operations. We have also entered into leases for certain vehicles and other equipment which are immaterial to our financial statements and have therefore not been recorded on our Consolidated Balance Sheets.

The lease cost components for the three and six months ended June 30, 2019 are classified as follows:

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Consolidated Statements of Operations Classification
Building lease cost	$	403	$	756	General and administrative expense
Variable lease cost (1)		48		95	General and administrative expense
	$	451	$	851

(1) Includes building operating expenses.

The following are additional details related to our lease portfolio as of June 30, 2019:

(in thousands)	June 30, 2019			Consolidated Balance Sheets Classification
Lease asset, gross	$	2,922		Furniture, fixtures and equipment and other capital assets
Accumulated depreciation		(626	)	Accumulated depletion, depreciation and amortization
Lease asset, net	$	2,296
Current lease liability	$	1,359		Accrued liabilities
Non-current lease liability		1,523		Other non-current liabilities
Total lease liabilities	$	2,882

20

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents operating lease liability maturities as of June 30, 2019:

(in thousands)	June 30, 2019
2019	$	770
2020		1,540
2021		813
2022		-
2023		-
Thereafter		-
Total lease payments	$	3,123
Less imputed interest		241
Present value of lease liabilities	$	2,882

The future minimum obligations under operating leases in effect as of December 31, 2018 having a noncancelable term in excess of one year as determined prior to the adoption of ASU 842 are as follows:

(in thousands)	December 31, 2018
2019	$	3,753
2020		1,556
2021		513
2022		-
2023		-
Thereafter		-
Future minimum lease obligations	$	5,822

As of June 30, 2019, our office building operating lease has a weighted-average remaining lease term of 1.8 years and a weighted-average discount rate of 8.0 percent. Cash paid for amounts included in the measurement of operating lease liabilities was $0.4 million and $0.8 million for the three and six months ended June 30, 2019, respectively.

NOTE 11—Dispositions

On March 1, 2019, the Company closed on the sale of working interests in certain non-core Haynesville Shale Trend oil and gas leases and related facilities in Caddo Parish, Louisiana for total consideration of $1.3 million, subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheets.

On May 21, 2018, the Company closed on the sale of working interests in certain oil and gas leases, including wells, facilities and leasehold acres, in our Tuscaloosa Marine Shale Trend operating area located in East and West Feliciana Parish, Louisiana for total consideration of approximately $3.3 million with an effective date of May 1, 2018. The disposition was subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet.

On February 28, 2018, the Company closed, in two separate transactions, the sale of working interests in certain oil and gas leases, wells, units and facilities and certain net leasehold interests in a portion of its undeveloped acreage in the Angelina River Trend in Angelina and Nacogdoches Counties, Texas to BP America Production Company for total consideration of $23.0 million, with an effective date of January 1, 2018. The disposition was subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet. The Company utilized the proceeds from these dispositions to pay down the outstanding balance of the 2017 Senior Credit Facility on March 2, 2018 and to fund our capital expenditures program.

The Company also sold other miscellaneous acreage during the three and six months ended June 30, 2018 for $0.4 million and $0.7 million, respectively, which was also recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet.

21

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

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with our management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), concerning our operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:

• the market prices of oil and natural gas;

• volatility in the commodity-futures market;

• financial market conditions and availability of capital;

• future cash flows, credit availability and borrowings;

• sources of funding for exploration and development;

• our financial condition;

• our ability to repay our debt;

• the securities, capital or credit markets;

• planned capital expenditures;

• future drilling activity;

• uncertainties about the estimated quantities of our oil and natural gas reserves;

• production;

• hedging arrangements;

• litigation matters;

• pursuit of potential future acquisition opportunities;

• general economic conditions, either nationally or in the jurisdictions in which we are doing business;

• legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;

• the creditworthiness of our financial counter-parties and operation partners; and

• other factors discussed below and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings, press releases and discussions with our management.

For additional information regarding known material factors that could cause our actual results to differ from projected results please read the rest of this report and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018.

22

Overview

Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the "Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.

We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities (“operating cash flow”). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.

We strive to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our Board of Directors (the “Board”) on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities, and strategic joint ventures, when establishing our capital expenditure budget.

We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments.

Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control; however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.

Primary Operating Areas

Haynesville Shale Trend

Our relatively low risk development acreage in this trend is primarily centered in Caddo, DeSoto and Red River parishes, Louisiana and Angelina and Nacogdoches counties, Texas. We have acquired or farmed-in leases totaling approximately 39,000 gross (22,000 net) acres as of June 30, 2019 in the Haynesville Shale Trend. We completed and produced 3 gross (2.6 net) new wells in the second quarter of 2019 and had 5 gross (2.7 net) wells in the drilling or completions phase as of June 30, 2019. Our net production volumes from our Haynesville Shale Trend wells represented approximately 98% of our total equivalent production on a Mcfe basis and substantially all of our natural gas production for the second quarter of 2019. We are focusing on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend, where we plan to focus all of our 2019 drilling efforts.

Tuscaloosa Marine Shale Trend

We have acquired approximately 49,000 gross (34,000 net) lease acres in the TMS as of June 30, 2019 with approximately 48,000 gross (33,000 net) acres held by production. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. Our net production volumes from our TMS wells represented approximately 2% of our total equivalent production on a Mcfe basis and substantially all of our total oil production for the second quarter of 2019. Despite no capital expenditures, we are seeking to maintain production through strategic expense workover operations in the TMS.

Eagle Ford Shale Trend

We have retained approximately 12,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas as of June 30, 2019, which is prospective for future development or sale.

23

Results of Operations

The item that had the most material financial effect on our net income of $11.8 million for the three months ended June 30, 2019 was a $12.7 million gain on derivatives not designated as hedges. The majority of the gain was attributable to mark-to-market valuation of our derivative positions due to natural gas futures prices being lower than our fixed prices. The items that had the most material financial effect on our net income of $12.2 million for the six months ended June 30, 2019 in addition to the derivative gains mentioned above were oil and gas revenues, transportation and processing expense and depletion, depreciation and amortization expense. All these items increased compared to the six months ended June 30, 2018, which is primarily attributable to production volume increases.

The items that had the most material financial effect on our net loss of $2.7 million for the three months ended June 30, 2018 and net loss of $8.0 million for the six months ended June 30, 2018 were a $2.2 million and $3.2 million loss, respectively, on our commodity derivatives not designated as hedges and interest expense of $2.7 million and $5.4 million, respectively.

We recognized operating income in each period presented due to our increasing revenues attributed to increased production volumes.

The following table reflects our summary operating information for the periods presented (in thousands, except for price and volume data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.

Revenues from Operations

	Three Months Ended June 30,									Six Months Ended June 30,
(In thousands, except for price and average daily production data)	2019		2018		Variance					2019		2018		Variance
Revenues:
Natural gas	$	28,942	$	13,816	$	15,126		109	%	$	55,302	$	21,717	$	33,585		155	%
Oil and condensate		2,944		3,968		(1,024	)	(26	)%		5,730		7,910		(2,180	)	(28	)%
Natural gas, oil and condensate		31,886		17,784		14,102		79	%		61,032		29,627		31,405		106	%
Net Production:
Natural gas (Mmcf)		12,305		5,170		7,135		138	%		21,366		8,122		13,244		163	%
Oil and condensate (MBbls)		45		57		(12	)	(21	)%		92		118		(26	)	(22	)%
Total (Mmcfe)		12,577		5,513		7,064		128	%		21,918		8,829		13,089		148	%
Average daily production (Mcfe/d)		138,208		60,582		77,626		128	%		121,096		48,779		72,317		148	%
Average realized sales price per unit:
Natural gas (per Mcf)	$	2.35	$	2.67	$	(0.32	)	(12	)%	$	2.59	$	2.67	$	(0.08	)	(3	)%
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives	$	2.54	$	2.76	$	(0.22	)	(8	)%	$	2.62	$	2.74	$	(0.12	)	(4	)%
Oil and condensate (per Bbl)	$	65.00	$	69.39	$	(4.39	)	(6	)%	$	62.18	$	67.12	$	(4.94	)	(7	)%
Oil and condensate (per Bbl) including the effect of realized losses on derivatives	$	59.28	$	58.69	$	0.59		1	%	$	58.16	$	58.33	$	(0.17	)	(0	)%
Average realized price (per Mcfe)	$	2.54	$	3.23	$	(0.69	)	(21	)%	$	2.78	$	3.36	$	(0.58	)	(17	)%

Natural gas, oil and condensate revenues increased by $14.1 million and $31.4 million, respectively for the three and six months ended June 30, 2019 compared to the same periods in 2018. The increase was primarily driven by increased natural gas production offset by lower realized commodity prices and decreased oil production. The increase in natural gas production volumes is attributed to three operated Haynesville Shale Trend wells completed in the second quarter of 2019 and the continued production of an additional five operated and six non-operated Haynesville Shale Trend wells completed since the second quarter of 2018. We have brought 14 gross (8.0 net) Haynesville Trend wells on production since June 30, 2018. For the three and six months ended June 30, 2019, 91% of our oil and natural gas revenue was attributable to natural gas sales compared to 78% and 73%, respectively for the three and six months ended June 30, 2018.

24

Operating Expenses

As described below, total operating expenses increased $11.8 million to $27.5 million for the three months ended June 30, 2019 and increased $22.7 million to $51.6 million for the six months ended June 30, 2019, compared to the same periods in 2018. The increase in total operating expenses for the three and six months ended June 30, 2019 was primarily due to the increase in the number of producing wells and an increase in depreciation, depletion and amortization, transportation expense and lease operating expense discussed further below.

	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses (in thousands)	2019		2018		Variance					2019		2018		Variance
Lease operating expenses	$	2,978	$	2,465	$	513		21	%	$	6,313	$	5,031	$	1,282		25	%
Production and other taxes		624		669		(45	)	(7	)%		1,255		1,309		(54	)	(4	)%
Transportation and processing		5,754		2,086		3,668		176	%		10,455		3,398		7,057		208	%
Operating Expenses per Mcfe
Lease operating expenses	$	0.24	$	0.45	$	(0.21	)	(47	)%	$	0.29	$	0.57	$	(0.28	)	(49	)%
Production and other taxes	$	0.05	$	0.12	$	(0.07	)	(58	)%	$	0.06	$	0.15	$	(0.09	)	(60	)%
Transportation and processing	$	0.46	$	0.38	$	0.08		21	%	$	0.48	$	0.38	$	0.10		26	%

Lease Operating Expense

Lease operating expense (“LOE”) increased $0.5 million to $3.0 million and increased $1.3 million to $6.3 million, respectively, during the three and six months ended June 30, 2019 compared to the same periods in 2018. The increase in LOE between periods was totally attributable to increased production volumes which increased variable lease operating costs such as saltwater disposal and equipment rental expenses while fixed expenses remained relatively the same between periods. The per unit cost of production has been driven down to $0.24 per mcfe and $0.29 per mcfe, respectively, for the three and six months ended June 30, 2019. Per unit LOE is expected to continue to decrease as we increase production in the Haynesville Shale Trend, which carries a much lower per unit LOE than the Company’s current per unit rate.

Production and Other Taxes

Production and other taxes includes severance and ad valorem taxes. Severance taxes were $0.4 million and $0.7 million respectively for the three and six months ended June 30, 2019, which were relatively unchanged from the same periods in 2018. Ad valorem taxes were $0.2 million and $0.5 million, respectively, for the three and six months ended June 30, 2019, also relatively unchanged from the same periods in 2018. The State of Louisiana has enacted an exemption from the existing 12.5% severance tax on oil and from the $0.111 per Mcf (from July 1, 2017 through June 30, 2018) and $0.122 per Mcf (starting on July 1, 2018) severance tax on natural gas for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) payout of the well. Our recently drilled Haynesville Shale Trend wells in Northwest Louisiana are benefiting from this exemption. Though ad valorem tax remained relatively unchanged between the periods presented, we expect ad valorem taxes to increase as our newly producing wells begin to be valued by the taxing jurisdictions. 

25

Transportation and Processing

Transportation and processing expense for the three and six months ended June 30, 2019 increased compared to the same periods in 2018, reflecting increased production from our Haynesville Shale Trend wells. Our natural gas volumes from our operated wells generally carry less transportation cost per Mcf than wells we do not operate. Despite an increase in our operated natural gas production volumes between periods, our cost per Mcfe increased for the three and six months ended June 30, 2019 compared to the same periods in 2018. This per unit increase is partially attributed to the mix of oil and natural gas production volumes during each period as our oil production is decreasing and not burdened by transportation and processing cost. Additionally, the wells we have recently put on production are producing from leases that stipulate that the royalty is free from transportation cost; consequently, we currently are incurring a proportionately higher transportation cost on the production from those wells. 

	Three Months Ended June 30,										Six Months Ended June 30,
Operating Expenses (in thousands):	2019			2018		Variance					2019			2018		Variance
Depreciation, depletion and amortization	$	13,299		$	5,560	$	7,739		139	%	$	23,345		$	9,012	$	14,333		159	%
General and administrative		4,936			4,803		133		3	%		10,246			9,999		247		2	%
Other		(59	)		165		(224	)	(136	)%		(49	)		165		(214	)	(130	)%
Operating Expenses per Mcfe
Depreciation, depletion and amortization	$	1.06		$	1.01	$	0.05		5	%	$	1.07		$	1.02	$	0.05		5	%
General and administrative	$	0.39		$	0.87	$	(0.48	)	(55	)%	$	0.47		$	1.13	$	(0.66	)	(58	)%
Other	$	-		$	0.03	$	(0.03	)	(100	)%	$	-		$	0.02	$	(0.02	)	(100	)%

Depreciation, Depletion and Amortization (“DD&A”)

DD&A expense is calculated on the Full Cost Method using the units of production (the “UOP”) method. The increase in DD&A expense was attributed primarily to increased production as well as an increased DD&A rate for the three and six months ended June 30, 2019 as compared to the same period in 2018. The increased rate takes into account the increasing and estimated future cost of drilling and completing wells.

General and Administrative (“G&A”)

The Company recorded $4.9 million and $10.2 million respectively in G&A expense for the three and six months ended June 30, 2019, which is an increase of $0.1 million and $0.2 million, respectively, compared to the same periods in 2018. G&A expense for 2019 included increased legal fees due to preparation of the Notice of Stockholder Action by Written Consent and preparation of the annual Proxy, which provided for changes to the Original Certificate of Incorporation. The Written Consent and Proxy were filed with the Securities and Exchange Commission on June 24, 2019 and July 19, 2019, respectively. G&A expense for the three and six months ended June 30, 2019 included non-cash expenses of $1.6 million and $3.1 million, respectively, for share-based compensation, which is virtually unchanged from the same periods in 2018.

Other Income (Expense)

	Three Months Ended June 30,											Six Months Ended June 30,
Other income (expense) (in thousands):	2019			2018			Variance					2019			2018			Variance
Interest expense	$	(3,398	)	$	(2,732	)	$	(666	)	24	%	$	(7,055	)	$	(5,405	)	$	(1,650	)	31	%
Interest income and other		18			116			(98	)	84	%		24			109			(85	)	78	%
Gain (loss) on commodity derivatives not designated as hedges		12,653			(2,174	)		14,827		(682	)%		11,645			(3,155	)		14,800		(469	)%
Loss on early extinguishment of debt		(1,846	)		-			(1,846	)	(100	)%		(1,846	)		-			(1,846	)	(100	)%
Average funded borrowings adjusted for debt discount	$	101,408		$	43,401		$	58,007		134	%	$	91,055		$	46,875		$	44,180		94	%
Average funded borrowings	$	104,716		$	50,194		$	54,522		109	%	$	94,659		$	54,119		$	40,540		75	%

Interest Expense

Interest expense for the three and six months ended June 30, 2019 reflected interest payable in cash of $1.0 million and $1.5 million, respectively, incurred on the 2017 Senior Credit Facility and 2019 Senior Credit Facility and non-cash interest of $2.4 million and $5.6 million, respectively, incurred primarily on the Company's Convertible Second Lien Notes and New 2L Notes,which included $1.4 million and $3.2 million, respectively, of paid in-kind interest and $1.0 million and $2.4 million, respectively, of debt discount and debt issuance cost amortization.

Interest expense for the three and six months ended June 30, 2018 reflected cash interest of $0.1 million and $0.2 million, respectively, incurred on the 2017 Senior Credit Facility and non-cash interest of $2.6 million and $5.2 million, respectively, incurred on the Company's Convertible Second Lien Notes, which included $1.6 million and $3.2 million, respectively, of paid in-kind interest and $1.0 million and $1.8 million, respectively, of debt discount and debt issuance cost amortization.

Interest expense increased in the 2019 periods presented compared to the same periods in 2018 due to increased funded debt, mainly resulting from the accretion of the paid in-kind interest on our Convertible Second Lien Notes. On May 29, 2019, we redeemed our Convertible Second Lien Notes using borrowings from our 2019 Senior Credit Facility and recorded a $1.8 million loss on early extinguishment of debt. On May 31, 2019, we issued $12.0 million of new convertible second lien notes. The result of these transactions going forward will result in the Company incurring less interest expense overall but an increase in interest payable in cash.

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Gain (Loss) on Commodity Derivatives Not Designated as Hedges

 Gain on commodity derivatives not designated as hedges for the three months ended June 30, 2019 was comprised of a mark-to-market gain of $10.7 million, representing the change of the fair value of our natural gas derivative contracts from March 31, 2019, and a $2.0 million gain on cash settlements during the period. Gain on commodity derivatives not designated as hedges for the six months ended June 30, 2019 was comprised of a mark-to-market gain of $11.4 million, representing the change of the fair value of our natural gas derivative contracts from December 31, 2018, and a $0.2 million gain on net cash settlements during the period. Natural gas futures prices fell appreciably below our fixed contract prices in the second quarter of 2019 resulting in our derivative asset position. Since we do not apply hedge accounting on our derivatives contracts there can be large swings in our reported gain or losses between periods. Going forward, any increase in natural gas futures prices would result in recording of losses in future periods. 

Loss on commodity derivatives not designated as hedges for the three and six months ended June 30, 2018 was comprised of a mark-to-market loss of $2.0 million and $2.6 million, respectively, representing the change of the fair value of our open natural gas and oil derivative contracts, as well as a loss of $0.2 million and $0.5 million, respectively, on cash settlements of natural gas and oil derivative contracts.

Reorganization gain (loss), net

We settled all of our bankruptcy claims and closed our bankruptcy case in the in the second quarter of 2018 incurring final trustee and legal fees of $0.3 million in 2018.

Income Tax Benefit

We recorded no income tax expense or benefit for the three or six months ended June 30, 2019. We recorded a valuation allowance for our net deferred tax asset at December 31, 2016. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our history of net operating losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. The valuation allowance was $84.1 million as of December 31, 2018, which resulted in a net non-current deferred tax asset of $0.8 million appearing on our statement of financial position. The net $0.8 million deferred tax asset relates to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability. Considering the Company’s taxable income forecasts, our assessment of the realization of our deferred tax assets has not changed, and we continue to maintain a full valuation allowance for our net deferred tax assets as of June 30, 2019 aside from the deferred tax asset related to the AMT credits.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-United States Generally Accepted Accounting Principle (“US GAAP”) financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income and similar tax, DD&A, share-based compensation expense and impairment of oil and natural gas properties (if any). In calculating Adjusted EBITDA, gains/losses on reorganization and mark-to-market gains/losses on commodity derivatives not designated as hedges are also excluded. Other excluded items include adjustments resulting from the accounting for operating leases under Accounting Standards Codification (“ASC”) 842, interest income and any extraordinary non-cash gains or losses. Adjusted EBITDA is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA should not be considered an alternative to net income (loss), as defined by US GAAP.

The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDA to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP:

	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2019			2018			2019			2018
Net income (loss) (US GAAP)	$	11,779		$	(2,661	)	$	12,227		$	(7,985	)
Interest expense		3,398			2,732			7,055			5,405
Depreciation, depletion and amortization		13,299			5,560			23,345			9,012
Share-based compensation expense (non-cash)		1,580			1,491			3,148			3,167
(Gain) loss on commodity derivatives not designated as hedges, not settled		(10,680	)		2,018			(11,432	)		2,614
Loss on early extinguishment of debt		1,846			-			1,846			-
Other items (1)		311			(240	)		558			98
Adjusted EBITDA	$	21,533		$	8,900		$	36,747		$	12,311

(1) Other items include $0.3 million, zero, $0.6 million and zero, respectively from the impact of accounting for operating leases under ASC 842 as well as interest income, reorganization items and other non-recurring income and expense.

Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry.

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Liquidity and Capital Resources

Overview

On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amends, restates and refinances the obligations under our 2017 Credit Agreement.

The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) the date that is 180 days prior to the “Maturity Date” as defined in the indenture governing the New 2L Notes (the “New 2L Notes Indenture”) as in effect on the issuance date of the New 2L Notes if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by such date. The maximum credit amount under the 2019 Senior Credit Facility is currently $500 million with an initial borrowing base of $115 million. The borrowing base is scheduled to be redetermined in August of 2019 and in March and September of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company issued to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering occurred on May 31, 2019. Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. Holders of the New 2L Notes have a second priority lien on all assets of the Company.

The New 2L Notes, as set forth in the New 2L Notes Indenture, are scheduled to mature on May 31, 2021.  The New 2L Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the New 2L Notes by increasing the principal amount of the outstanding New 2L Notes.

Our primary sources of cash during the first six months of 2019 were cash on hand, cash from operating activities, net proceeds from borrowings on our senior credit facilities and proceeds from the sale of assets. We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 2019 through a combination of cash on hand, cash from operating activities and borrowing under the 2019 Senior Credit Facility, although we may from time to time consider the funding alternatives described below.

We exited the second quarter of 2019 with $1.7 million of cash on hand and $84.4 million of outstanding borrowings with $30.6 million of availability under the 2019 Senior Credit Facility borrowing base. Due to the timing of payment of our capital expenditures, we reflected a working capital deficit of $19.7 million as of June 30, 2019. To the extent we operate with a working capital deficit, we expect such deficit to be offset by liquidity available under our 2019 Senior Credit Facility.

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We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed.

Alternatives available to us include:

• availability under the 2019 Senior Credit Facility;

• issuance of debt securities;

• joint ventures in our TMS and/or Haynesville Shale Trend acreage;

• sale of non-core assets; and

• issuance of equity securities if favorable conditions exist.

We have supported our cash flows with derivative contracts that covered approximately 74% of our natural gas sales volumes for the first six months of 2019 and 65% of our oil volumes for the first six months of 2019. For additional information on our derivative instruments see Note 8—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Cash flow statement information:
Net cash:
Provided by operating activities	$	23,346		$	6,399		$	41,253		$	12,655
Used in investing activities		(26,812	)		(20,399	)		(53,782	)		(26,180	)
Provided by (used in) financing activities		5,135			5,998			10,130			(10,738	)
Decrease in cash and cash equivalents	$	1,669		$	(8,002	)	$	(2,399	)	$	(24,263	)

Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations for the three and six months ended June 30, 2019. Changes in working capital and net cash settlements related to our derivative contracts also impact cash flows. Net cash provided by operating activities for the three months ended June 30, 2019 was $23.3 million including operating cash flows before working capital changes of $20.6 million which included $2.0 million net cash received from settled derivative contracts. Net cash provided by operating activities for the three months ended June 30, 2018 was $6.4 million including operating cash flows before working capital changes of $9.2 million reduced by net cash payments of $0.2 million in settlement of derivative contracts. Net cash provided by operating activities for the six months ended June 30, 2019 was $41.3 million including operating cash flows before working capital changes of $35.4 million which included $0.2 million net cash received from settled derivative contracts. Net cash provided by operating activities for the six months ended June 30, 2018 was $12.7 million including operating cash flows before working capital changes of $12.5 million reduced by net cash payments of $0.5 million in settlement of derivative contracts. Net cash provided by operating activities increased in the periods presented in 2019 compared to the same periods in 2018 driven by production volume increases, use of working capital and net cash receipts on settled derivative contracts reduced by a decrease in commodity prices.

Investing activities:Net cash used in investing activities was $53.8 million for the six months ended June 30, 2019. We paid out cash amounts totaling $55.1 million for drilling and development operations during the period versus recorded capital expenditures of $54.5 million. The difference is attributed to cash payments of $1.0 million of costs incurred in the prior period offset by non-cash internal costs of $0.4 million. The period also reflects the receipt of $1.3 million in proceeds from the sales of non-core oil and gas properties. We conducted drilling operations on 8 wells and completed 5 wells all in the Haynesville Shale Trend during the six months ended June 30, 2019, capitalizing $1.8 million in internal costs. Net cash used in investing activities was $26.8 million for the three months ended June 30, 2019 which reflected cash expended on capital projects. We recorded $25.0 million in capital expenditures in this period. The difference in capital expenditures and cash expended on capital projects for the three months ended June 30, 2019 was attributed to a net capital accrual decrease of $2.1 million offset by $0.3 million of non-cash internal costs.

Financing activities: Net cash provided by financing activities for the three and six months ended June 30, 2019 reflects primarily net borrowings under our revolving credit facilities as well as the payoff of the Convertible Second Lien Notes and issuance of the New 2L Notes along with associated issuance costs paid in connection with such transactions.

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Debt consisted of the following balances as of the dates indicated (in thousands):

	June 30, 2019				December 31, 2018
	Principal		Carrying Amount		Principal		Carrying Amount
2017 Senior Credit Facility	$	-	$	-	$	27,000	$	27,000
2019 Senior Credit Facility		84,400		84,400		-		-
Convertible Second Lien Notes (1)		-		-		53,691		49,820
New 2L Notes (2)		12,135		10,504		-		-
Total debt	$	96,535	$	94,904	$	80,691	$	76,820

(1) The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019.

(2) The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2021. The principal included $0.1 million of accrued interest to be paid in-kind as of June 30, 2019. The carrying value included $1.4 million of unamortized debt discount as of June 30, 2019.

For additional information on our financing activities, see Note 4—“Debt” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements for any purpose.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements, which were prepared in accordance with US GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, 2018 includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three months ended June 30, 2019.

Item 3—Quantitative and Qualitative Disclosures about Market Risk

Our primary market risks are attributable to fluctuations in commodity prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. Our risk-management policies provide for the use of derivative instruments to manage these risks. The types of derivative instruments we utilize include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments we utilize may vary from year to year and is governed by risk-management policies with levels of authority delegated by our Board. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and we may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counter-parties in order to satisfy these margin requirements.

For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Note 1—“Description of Business and Significant Accounting Policies”, Note 4—“Debt” and Note 8—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.

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Commodity Price Risk

Our most significant market risk relates to fluctuations in crude oil and natural gas prices. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, a non-cash write-down of our oil and natural gas properties may be required if future commodity prices experience a sustained and significant decline. We have entered into natural gas and oil derivative instruments in order to reduce the price risk associated with production for the remainder of 2019 of approximately 100,000 MMBtu and 300 barrels per day, respectively, for 2020 of 33,344 MMBtu and 221 barrels per day, respectively, and for the first quarter of 2021 for 16,656 MMBtu and 200 barrels per day, respectively. We did not enter into derivative instruments for trading purposes. Utilizing actual derivative contractual volumes, a hypothetical increase of 10% in the underlying commodity prices would have decreased the natural gas asset position by $7.7 million and increased the derivative oil liability position by $0.8 million as of June 30, 2019. Likewise, a hypothetical decrease of 10% in the underlying commodity prices would have increased the derivative natural gas asset position by $7.8 million and changed the derivative oil liability position to an asset position with a change of $0.9 million as of June 30, 2019. Furthermore, a gain or loss would have been substantially offset by an increase or decrease, respectively, in the actual sales value of production covered by the derivative instruments.

Adoption of Comprehensive Financial Reform

The adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Item 4—Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of June 30, 2019, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1—Legal Proceedings

A discussion of our current legal proceedings is set forth in Part I, Item 1 under Note 9—“Commitments and Contingencies” to the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

As of June 30, 2019, we did not have any material outstanding and pending litigation.

Item 1A—Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our business, financial condition or future results.

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

As described under Item 2—Management's Discussion and Analysis of Results of Operations and Financial Condition, the Company issued the New 2L Notes on May 31, 2019. The New 2L Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of New 2L Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be $21.33, subject to certain adjustments as described in the indenture governing the New 2L Notes (the “New 2L Notes Indenture”). Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the New 2L Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company's ability to redeem the New 2L Notes with cash is subject to the terms of the 2019 Senior Credit Agreement.

The New 2L Notes were issued and sold to the New 2L Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereunder. The New 2L Notes Purchasers may only resell the New 2L Notes to qualified institutional buyers in accordance with Rule 144A under the Securities Act and to certain persons outside the United States in accordance with Regulation S under the Securities Act. The New 2L Notes were not registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws.

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Item 6—Exhibits

3.1	Second Amended and Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated October 12, 2016, (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
3.2	Second Amended and Restated Bylaws of Goodrich Petroleum Corporation, dated October 12, 2016, (Incorporated by reference to Exhibit 4.2 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
4.1	Indenture, dated as of May 31, 2019, by and between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C., as the subsidiary guarantor, and Wilmington Trust, National Association, as trustee and collateral agent, relating to the 13.50% Convertible Second Lien Senior Secured Notes due 2021 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on June 3, 2019).
4.2	Registration Rights Agreement, dated as of May 31, 2019, by and among Goodrich Petroleum Corporation and the Holders party thereto, relating to the New 2L Notes (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on June 3, 2019).
10.1	Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 14, 2019, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, SunTrust Bank, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 14, 2019).
10.2	Note Purchase Agreement, dated as of May 14, 2019, by and among Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C., as subsidiary guarantor, and certain funds and accounts managed by Franklin Advisers, Inc. as investment manager (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 14, 2019).
31.1*	Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Labels Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*	Filed herewith
**	Furnished herewith

33

SIGNATURES

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

	GOODRICH PETROLEUM CORPORATION (Registrant)
Date: August 7, 2019	By:	/S/ Walter G. Goodrich
		Walter G. Goodrich
		Chairman & Chief Executive Officer
Date: August 7, 2019	By:	/S/ Robert T. Barker
		Robert T. Barker
		Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer

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EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Walter G. Goodrich, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Goodrich Petroleum Corporation (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: August 7, 2019

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Robert T. Barker certify that:

1. I have reviewed this quarterly report on Form 10-Q of Goodrich Petroleum Corporation (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: August 7, 2019

/s/ Robert T. Barker

Robert T. Barker

Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report of Goodrich Petroleum Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Walter G. Goodrich, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

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

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

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer

August 7, 2019

This certification is provided pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company or the certifying officer for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by it and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report of Goodrich Petroleum Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert T. Barker, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

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

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

/s/ Robert T. Barker

Robert T. Barker

Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer

August 7, 2019

This certification is provided pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company or the certifying officer for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by it and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 07, 2019
Document Information [Line Items]
Entity Registrant Name	GOODRICH PETROLEUM CORP
Entity Central Index Key	0000943861
Trading Symbol	gdp
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Common Stock, Shares Outstanding (in shares)		12,303,718
Entity Shell Company	false
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Title of 12(b) Security	Common Stock

XML

Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents	$ 1,669	$ 4,068
Accounts receivable, trade and other, net of allowance	2,660	744
Accrued oil and natural gas revenue	15,869	14,464
Fair value of oil and natural gas derivatives	11,421	803
Inventory	584	596
Prepaid expenses and other	374	533
Total current assets	32,577	21,208
PROPERTY AND EQUIPMENT:
Unevaluated properties	105	180
Oil and natural gas properties (full cost method)	259,247	206,097
Furniture, fixtures and equipment and other capital assets	4,359	1,360
	263,711	207,637
Less: Accumulated depletion, depreciation and amortization	(66,272)	(42,447)
Net property and equipment	197,439	165,190
Fair value of oil and natural gas derivatives	719
Deferred tax asset	786	786
Other	2,220	580
TOTAL ASSETS	233,741	187,764
CURRENT LIABILITIES:
Accounts payable	35,897	25,734
Accrued liabilities	16,044	16,518
Fair value of oil and natural gas derivatives	376
Total current liabilities	52,317	42,252
Long term debt, net	94,904	76,820
Accrued abandonment cost	3,963	3,791
Fair value of oil and natural gas derivatives		471
Other non-current liabilities	1,523
Total liabilities	152,707	123,334
Commitments and contingencies (See Note 9)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding	0	0
Common stock: $0.01 par value, 75,000,000 shares authorized, and 12,302,318 and 12,150,918 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively	123	122
Treasury stock: 46,781 and zero shares as of June 30, 2019 and December 31, 2018, respectively	(543)
Additional paid in capital	79,780	74,861
Accumulated earnings (deficit)	1,674	(10,553)
Total stockholders’ equity	81,034	64,430
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 233,741	$ 187,764

XML

Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Preferred Stock, Par Value (in dollars per share)	$ 1	$ 1
Preferred Stock, Shares Authorized (in shares)	10,000,000	10,000,000
Preferred Stock, Shares Issued (in shares)	0	0
Preferred Stock, Shares Outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	75,000,000	75,000,000
Common stock, shares issued (in shares)	12,302,318	12,150,918
Common stock, shares outstanding (in shares)	12,302,318	12,150,918
Treasury stock, shares (in shares)	46,781	0

XML

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
REVENUES:
Revenues		$ 31,884	$ 17,835	$ 61,024	$ 29,669
OPERATING EXPENSES:
Lease operating expense		2,978	2,465	6,313	5,031
Production and other taxes		624	669	1,255	1,309
Transportation and processing		5,754	2,086	10,455	3,398
Depreciation, depletion and amortization		13,299	5,560	23,345	9,012
General and administrative		4,936	4,803	10,246	9,999
Other		(59)	165	(49)	165
		27,532	15,748	51,565	28,914
Operating income		4,352	2,087	9,459	755
OTHER INCOME (EXPENSE):
Interest expense		(3,398)	(2,732)	(7,055)	(5,405)
Interest income and other expense		18	116	24	109
Gain (loss) on commodity derivatives not designated as hedges		12,653	(2,174)	11,645	(3,155)
Loss on early extinguishment of debt		(1,846)		(1,846)
		7,427	(4,790)	2,768	(8,451)
Reorganization items, net			42		(289)
Income (loss) before income taxes		11,779	(2,661)	12,227	(7,985)
Income tax benefit		0	0	0	0
Net income (loss)		$ 11,779	$ (2,661)	$ 12,227	$ (7,985)
PER COMMON SHARE
Net income (loss) per common share - basic (in dollars per share)		$ 0.96	$ (0.23)	$ 1	$ (0.70)
Net income (loss) per common share - diluted (in dollars per share)	[1],[2],[3]	$ 0.82	$ (0.23)	$ 0.85	$ (0.70)
Weighted average shares of common stock outstanding - basic (in shares)		12,211	11,629	12,181	11,424
Weighted average shares of common stock outstanding - diluted (in shares)		14,581	11,629	14,498	11,424
Oil and Gas [Member]
REVENUES:
Revenues		$ 31,886	$ 17,784	$ 61,032	$ 29,627
Service, Other [Member]
REVENUES:
Revenues		$ (2)	$ 51	$ (8)	$ 42

[1] Common shares issuable on assumed conversion of share-based compensation for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. (4)

[2] Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.

[3] Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 12,227	$ (7,985)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	23,345	9,012
Right of use asset depreciation	626
(Gain) loss on commodity derivatives not designated as hedges	(11,645)	3,155
Net cash received (paid) for settlement of derivative instruments	213	(541)
Share-based compensation (non-cash)	3,148	3,167
Amortization of finance cost, debt discount, paid in-kind interest and accretion	7,445	5,157
Reorganization items (non-cash), net		289
Other	12	218
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance	(1,916)	(598)
Accrued oil and natural gas revenue	(1,405)	(2,359)
Prepaid expenses and other	131	(20)
Accounts payable	10,163	3,936
Accrued liabilities	(1,091)	(776)
Net cash provided by operating activities	41,253	12,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(55,066)	(53,100)
Proceeds from sale of assets	1,284	26,920
Net cash used in investing activities	(53,782)	(26,180)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings	(49,500)	(16,723)
Proceeds from bank borrowings	106,900	6,000
Repayment of Convertible Second Lien Notes	(56,728)
Proceeds from New 2L Notes	12,000
Issuance cost, net	(2,000)	(10)
Purchase of treasury stock and other	(542)	(5)
Net cash provided by (used in) financing activities	10,130	(10,738)
Decrease in cash and cash equivalents	(2,399)	(24,263)
Cash and cash equivalents, beginning of period	4,068	25,992
Cash and cash equivalents, end of period	1,669	1,729
Supplemental disclosures of cash flow information:
Cash paid for reorganization items, net		543
Cash paid for interest	1,681	249
Increase (decrease) in non-cash capital expenditures	$ (1,019)	$ (2,805)

XML

Consolidated Statements of Stockholders' Equity/(Deficit) (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Convertible Second Lien Notes [Member] Preferred Stock [Member]	Convertible Second Lien Notes [Member] Common Stock [Member]	Convertible Second Lien Notes [Member] Additional Paid-in Capital [Member]	Convertible Second Lien Notes [Member] Treasury Stock [Member]	Convertible Second Lien Notes [Member] Retained Earnings [Member]	Convertible Second Lien Notes [Member]	New 2L Notes [Member] Preferred Stock [Member]	New 2L Notes [Member] Common Stock [Member]	New 2L Notes [Member] Additional Paid-in Capital [Member]	New 2L Notes [Member] Treasury Stock [Member]	New 2L Notes [Member] Retained Earnings [Member]	New 2L Notes [Member]	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Total
Balance (in shares) at Dec. 31, 2017														10,771
Balance at Dec. 31, 2017														$ 108	$ 68,446		$ (12,303)	$ 56,251
Net income (loss)																	(5,324)	(5,324)
Share-based compensation															1,776			1,776
Restricted stock vesting & other (in shares)														203		(75)
Restricted stock vesting & other														$ 2	2,224	$ (827)		1,399
Conversion of convertible securities (in shares)		589
Conversion of convertible securities		$ 6	$ (6)
Issuance cost															(34)			(34)
Balance (in shares) at Mar. 31, 2018														11,563		(75)
Balance at Mar. 31, 2018														$ 116	72,406	$ (827)	(17,627)	54,068
Balance (in shares) at Dec. 31, 2017														10,771
Balance at Dec. 31, 2017														$ 108	68,446		(12,303)	56,251
Net income (loss)																		(7,985)
Balance (in shares) at Jun. 30, 2018														11,837		(76)
Balance at Jun. 30, 2018														$ 119	74,135	$ (832)	(20,288)	53,134
Balance (in shares) at Mar. 31, 2018														11,563		(75)
Balance at Mar. 31, 2018														$ 116	72,406	$ (827)	(17,627)	54,068
Net income (loss)																	(2,661)	(2,661)
Share-based compensation															1,758			1,758
Restricted stock vesting & other (in shares)														1		(1)
Restricted stock vesting & other																$ (5)		(5)
Conversion of convertible securities (in shares)		273
Conversion of convertible securities		$ 3	1			4
Issuance cost															(30)			(30)
Balance (in shares) at Jun. 30, 2018														11,837		(76)
Balance at Jun. 30, 2018														$ 119	74,135	$ (832)	(20,288)	53,134
Balance (in shares) at Dec. 31, 2018														12,151
Balance at Dec. 31, 2018														$ 122	74,861		(10,553)	64,430
Net income (loss)																	448	448
Share-based compensation															1,745			1,745
Treasury stock activity (in shares)
Treasury stock activity																$ (5)		(5)
Treasury stock activity (in shares)														1
Balance (in shares) at Mar. 31, 2019														12,152
Balance at Mar. 31, 2019														$ 122	76,606	$ (5)	(10,105)	66,618
Balance (in shares) at Dec. 31, 2018														12,151
Balance at Dec. 31, 2018														$ 122	74,861		(10,553)	64,430
Net income (loss)																		12,227
Balance (in shares) at Jun. 30, 2019														12,302		47
Balance at Jun. 30, 2019														$ 123	79,780	$ (543)	1,674	81,034
Balance (in shares) at Mar. 31, 2019														12,152
Balance at Mar. 31, 2019														$ 122	76,606	$ (5)	(10,105)	66,618
Net income (loss)																	11,779	11,779
Share-based compensation															1,765			1,765
Conversion of convertible securities (in shares)		150
Conversion of convertible securities		$ 1	$ (20)			$ (19)			$ 1,429			$ 1,429
Treasury stock activity (in shares)																47
Treasury stock activity																$ (538)		(538)
Balance (in shares) at Jun. 30, 2019														12,302		47
Balance at Jun. 30, 2019														$ 123	$ 79,780	$ (543)	$ 1,674	$ 81,034

XML

Note 1 - Description of Business and Significant Accounting Policies

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Significant Accounting Policies [Text Block]

NOTE

1—Description

of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the “Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.

Basis of Presentation

The consolidated financial statements of the Company included in this Quarterly Report on Form

10

-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and accordingly, certain information normally included in financial statements prepared in accordance with United States Generally Accepted Accounting Principles (“US GAAP”) has been condensed or omitted. This information should be read in conjunction with our consolidated financial statements and notes contained in our annual report on Form

10

-K for the year ended 

December 31, 2018

. Operating results for the 

three

and

six

months ended

June 30, 2019

are

not

necessarily indicative of the results that

may

be expected for the full year or for any interim period.

Principles of Consolidation

—The consolidated financial statements include the financial statements of the Company and the Subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

Use of Estimates

— Our management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.

Cash and Cash Equivalents

—Cash and cash equivalents includes cash on hand, demand deposit accounts and temporary cash investments with maturities of

ninety

days or less at the date of purchase.

Accounts Payable

—Accounts payable consisted of the following amounts as of 

June 30, 2019

and 

December 31, 2018

:

(In thousands)	June 30, 2019		December 31, 2018
Trade payables	$	14,317	$	8,633
Revenue payables		21,057		16,665
Prepayments from partners		293		132
Miscellaneous payables		230		304
Total Accounts payable	$	35,897	$	25,734

Accrued Liabilities

—Accrued liabilities consisted of the following amounts as of 

June 30, 2019

and 

December 31, 2018

:

(In thousands)	June 30, 2019		December 31, 2018
Accrued capital expenditures	$	7,067	$	8,086
Accrued lease operating expense		936		1,100
Accrued production and other taxes		704		338
Accrued transportation and gathering		2,860		1,888
Accrued performance bonus		1,943		3,420
Accrued interest		216		443
Accrued office lease		1,359		598
Accrued general and administrative expense and other		959		645
Total Accrued liabilities	$	16,044	$	16,518

Inventory

—Inventory consists of casing and tubulars that are expected to be used in our capital drilling program. Inventory is carried on the Consolidated Balance Sheets at the lower of cost or market.

Property and Equipment

—Under US GAAP,

two

acceptable methods of accounting for oil and natural gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the

two

methods are in the treatment of exploration costs, the computation of depreciation, depletion and amortization (“DD&A”) expense and the assessment of impairment of oil and natural gas properties. We have elected to adopt the Full Cost Method of accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method better reflects the true economics of exploring for and developing our oil and gas reserves.

Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, but do

not

include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and natural gas properties and thereby subject to DD&A and the full cost ceiling test. For the

three

months ended

June 30, 2019

and

2018

, we transferred

$0.1

million and

$0.3

 million, respectively, 

from unevaluated properties to proved oil and natural gas properties. For the 

six

months ended

June 30, 2019

and

2018

, we transferred

$0.2

million and

$0.4

million, respectively, 

from unevaluated properties to proved oil and natural gas properties. Our sales of oil and natural gas properties are accounted for as adjustments to net proved oil and natural gas properties with

no

gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods' production also converted to Mcfe to arrive at the periods' DD&A expense.

Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from

three

to

five

years.

Full Cost Ceiling Test

—The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and natural gas properties, net of related deferred taxes. This comparison is referred to as a “ceiling test”. If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted future net cash flows from proved

reserves, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a

12

-month average pricing assumption.

There were

no

Full Cost Ceiling Test write-downs for the

three

or

six

months ended

June 30, 2019

or

2018

.

Fair Value Measurement

—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of non-performance, which includes, among other things, our credit risk.

We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value

may

be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into

three

levels (levels

1,

2

and

3

) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels and our corresponding instruments classified by level are further described below:

• Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;

• Level 2 Inputs— quotes that are derived principally from or corroborated by observable market data. Included in this level are our 2017 Senior Credit Facility and 2019 Senior Credit Facility (both as defined below) and commodity derivatives whose fair values are based on third -party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counter-parties; and

• Level 3 Inputs— unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this level would be our initial measurement of asset retirement obligations.

As of

June 30, 2019

and

December 31, 2018

, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

Asset Retirement Obligations

—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and natural gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations. See

Note

3

.

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligations was classified as Level

3

in the fair value hierarchy.

Revenue Recognition

—Oil and natural gas revenues are generally recognized upon delivery of our produced oil and natural gas volumes to our customers. We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales

may

not

be received for up to

60

days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record a liability or an asse

t for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. As of

June 30, 2019

and

December 31, 2018

, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted. See

Note

2

.

Derivative Instruments

—We use derivative instr

uments such as swaps, collars, futures, forwards and options for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counter-party for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All of our realized gain or losses on our derivative contracts are the result of cash settlements. We have

not

designated any of our derivative contracts as hedges; accordingly, changes in fair value are reflected in earnings. See

Note

8

.

Income Taxes

—We account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than

not

that some portion or all of the deferred tax assets will

not

be realized.

We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than

not

sustain the position following an audit. For tax positions meeting the more likely-than-

not

threshold, the amount recognized in the financial statements is the largest benefit that has a greater than

50

percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See

Note

7

.

Net Income or Net Loss Per Common Share—

Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted-average shares of common stock outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted average shares of common stock outstanding during the period, plus the effects of potentially dilutive restricted stock calculated using the treasury stock method and the potential dilutive effect of the conversion of convertible securities, such as warrants and convertible notes, into shares of our common stock. See

Note

6

.

Commitments and Contingencies

—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from

third

parties, when probable of realization, are separately recorded and are

not

offset against the related environmental liability. See

Note

9

.

Share-Based Compensation

—We account for our share-based transactions using the fair value as of the grant date and recognize compensation expense over the requisite service period.

Guarantee

—As of

June 30, 2019

, Goodrich Petroleum Company LLC, the wholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our New

2L

Notes (as defined below).

Debt Issuance Cost

—The Company records debt issuance costs associated with its New

2L

Notes (and previously with its Convertible Second Lien Notes, both as defined below) as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the life of the respective notes. Debt issuance costs associated with our revolving credit facility debt are recorded in other assets in our Consolidated Balance Sheets, which is amortized straight-line over the life of such debt.

New Accounting Pronouncements

On

August 28, 2018,

the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”)

2018

-

13,

Fair Value Measurements (Topic

820

): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“Topic

820”

). The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic

820

including the removal, modification and addition of certain disclosure requirements. For all entities, the amendments in this ASU are effective for fiscal periods beginning after

December 15, 2019,

including interim periods therein. We are evaluating the expected impact these amendments will have on our consolidated financial statements.

XML

Note 2 - Revenue Recognition

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Revenue from Contract with Customer [Text Block]

NOTE

2—Revenue

Recognition

On

January 1, 2018,

we adopted ASU

2014

-

09,

Revenue from Contracts with Customers,

and the series of related ASU's that followed under

Accounting Standards Codification (

“

ASC”) Topic

606

(collectively, “Topic

606”

).Topic

606

did

not

change our pattern of timing of revenue recognition. Under Topic

606,

revenue is generally recognized upon delivery of our produced oil and natural gas volumes to our customers. Our customer sales contracts include oil and natural gas sales. Under Topic

606,

each unit (Mcf or barrel) of commodity product represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of our contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced natural gas volumes passes to our customers at specific metered points indicated in our natural gas contracts. Similarly, control of our produced oil volumes passes to our customers when the oil is measured either by a trucking oil ticket or by a meter when entering an oil pipeline. The Company has

no

control over the commodities after those points and the measurement at those points dictates the amount on which the customer's payment is based. Our oil and natural gas revenue streams include volumes burdened by royalty and non-operated working interests. Our revenues are recorded and presented on our financial statements net of the royalty and non-operated working interests. Our revenue stream does

not

include any payments for services or ancillary items other than sale of oil and natural gas.

We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales

may

not

be received for up to

60

days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record any differences, which historically have

not

been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. As of 

June 30, 2019

and

December 31, 2018

, receivables from contracts with customers were

$15.9

million and

$14.5

 million, respectively.

The following table presents our revenues disaggregated by revenue source and by operated and non-operated properties for the 

three

and

six

months ended

June 30, 2019

and

2018

:

	Three Months Ended June 30, 2019								Six Months Ended June 30, 2019
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	2,805	$	25,163	$	-	$	27,968	$	5,516	$	45,337	$	-	$	50,853
Non-operated		139		3,775		4		3,918		214		9,957		8		10,179
Total oil and natural gas revenues	$	2,944	$	28,938	$	4	$	31,886	$	5,730	$	55,294	$	8	$	61,032

	Three Months Ended June 30, 2018								Six Months Ended June 30, 2018
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	3,835	$	10,900	$	-	$	14,735	$	7,634	$	16,701	$	-	$	24,335
Non-operated		133		2,912		4		3,049		276		5,008		8		5,292
Total oil and natural gas revenues	$	3,968	$	13,812	$	4	$	17,784	$	7,910	$	21,709	$	8	$	29,627

XML

Note 3 - Asset Retirement Obligations

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Asset Retirement Obligation Disclosure [Text Block]

NOTE

3—Asset

Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the 

six

months ended

June 30, 2019

is as follows (in thousands):

	Six Months Ended June 30, 2019
Beginning balance as of December 31, 2018	$	3,791
Liabilities incurred		82
Liabilities settled		(3	)
Dispositions		(53	)
Accretion expense		146
Ending balance as of June 30, 2019	$	3,963
Current liability	$	-
Long term liability	$	3,963

XML

Note 4 - Debt

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Debt Disclosure [Text Block]

NOTE

4—Debt

Debt consisted of the following balances as of 

June 30, 2019

and

December 31, 2018

(in thousands):

	June 30, 2019				December 31, 2018
	Principal		Carrying Amount		Principal		Carrying Amount
2017 Senior Credit Facility	$	-	$	-	$	27,000	$	27,000
2019 Senior Credit Facility		84,400		84,400		-		-
Convertible Second Lien Notes (1)		-		-		53,691		49,820
New 2L Notes (2)		12,135		10,504		-		-
Total debt	$	96,535	$	94,904	$	80,691	$	76,820

(

1

) The debt discount was being amortized using the effective interest rate method based upon a maturity date of

August 30, 2019

until the Convertible Second Lien Notes were fully paid off on

May 29, 2019.

(

2

) The debt discount is being amortized using the effective interest rate method based upon a maturity date of

May 31, 2021.

The principal included 

$0.1

million of accrued interest to be paid in-kind as of 

June 30, 2019

. The carrying value included 

$1.4

million of unamortized debt discount as of 

June 30, 2019

.

The following table summarizes the total interest expense for the 

three

and

six

months ended

June 30, 2019

and

2018

including contractual interest expense, amortization of debt discount and financing costs (amounts in thousands, except effective interest rates):

	Three Months Ended June 30, 2019					Three Months Ended June 30, 2018					Six Months Ended June 30, 2019					Six Months Ended June 30, 2018
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
2017 Senior Credit Facility	$	364		8.2	%	$	75	*			$	872		7.2	%	$	248		7.8	%
2019 Senior Credit Facility		695		5.9	%		-		-			695		5.9	%		-		-
Convertible Second Lien Notes (1)		2,155		23.9	%		2,657		24.7	%		5,304		24.1	%		5,157		24.8	%
New 2L Notes (2)		184		20.5	%		-		-			184		20.5	%		-		-
Total interest expense	$	3,398				$	2,732				$	7,055				$	5,405

(

1

) The Convertible Second Lien Notes had a coupon interest rate of

13.50%;

however, the discount recorded due to the convertibility of the notes increased the effective interest rate to

23.9%

and

24.1%,

respectively, for the

three

and

six

months ended

June 30, 2019

and

24.7%

and

24.8%,

respectively, for the

three

and

six

months ended

June 30, 2018. 

Interest expense for the

three

months ended

June 30, 2019

 includ

ed

$0.9

million of debt discount amortization and

$1.2

 million

of paid in-k

ind interest, and interest expense for the 

three

months ended

June 30, 2018

included

$1.0

million of debt discount amortization and

$1.6

 million of paid in-kind interest. Interest expense for the

six

months ended

June 30, 2019

 included

$2.3

million of debt discount amortization and

$3.0

million of paid in-kind interest, and interest expense for the

six

months ended

June 30, 2018 

included

$1.8

million of debt discount amortization and

$3.2

million of paid in-kind interest.

(

2

) The New

2L

Notes have a coupon interest rate of

13.50%;

however, the discount recorded due to the convertibility of the notes increased the effective interest rate to

20.5%

for the

three

and

six

months ended

June 30, 2019

. Interest expense for the 

three

and

six

months ended

June 30, 2019

 includ

ed less than

$0.1

 million of debt discount amortization and

$0.1

million

of accrued interest to be paid in-kind.

* - 

Not

meaningful due to the timing of borrowings during the

three

months ended

June 30, 2018.

2017

Senior Credit Facility

On

October 17, 2017,

the Company entered into the Amended and Restated Senior Secured Revolving Credit Agreement (as amended, the

“2017

Credit Agreement”) with the Subsidiary, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are party thereto, which provided for revolving loans of up to the borrowing base then in effect (as amended, the

“2017

Senior Credit Facility”). The

2017

Senior Credit Facility was set to mature on (a)

October 17, 2021

or (b)

December 30, 2019,

if the Convertible Second Lien Notes had 

not

been voluntarily redeemed, repurchased, refinanced or otherwise retired by

December 30, 2019.

The maximum credit amount under the

2017

Senior Credit Facility when it was paid off in full on

May 14, 2019

was

$250.0

million with a borrowing base of

$75.0

million.

All amounts outstanding under the

2017

Senior Credit Facility bore interest at a rate per annum equal to, at the Company's option, either (i) the alternative base rate plus an applicable margin ranging from

1.75%

to

2.75%,

depending on the percentage of the borrowing base that was utilized, or (ii) adjusted LIBOR plus an applicable margin ranging from

2.75%

to

3.75%,

depending on the percentage of the borrowing base that was utilized. Undrawn amounts under the

2017

Senior Credit Facility were subject to a

0.50%

commitment fee.

The obligations under the

2017

Credit Agreement were secured by a

first

lien security interest in substantially all of the assets of the Company and the Subsidiary.

On

May 14, 2019,

the

2017

Senior Credit Facility was paid off in full and amended, restated and refinanced into the

2019

Senior Credit Facility. In connection with the refinancing, we recorded a

$0.2

million loss on early extinguishment of debt related to the remaining unamortized debt issuance costs.

2019

Senior Credit Facility

On

May 14, 2019,

the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the

“2019

Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the

“2019

Senior Credit Facility”). The

2019

Senior Credit Facility amends, restates and refinances the obligations under the

2017

Credit Agreement.

The

2019

Senior Credit Facility matures (a) 

May 14, 2024

or (b) the date that is

180

days prior to the “Maturity Date” as defined in the New

2L

Notes Indenture (as defined below) as in effect on the date of issuance of the New

2L

Notes if the New

2L

Notes (as defined below) have

not

been voluntarily redeemed, repurchased, refinanced or otherwise retired by such date. The maximum credit amount under the

2019

Senior Credit Facility is currently

$500

million with an initial borrowing base of

$115

million. The borrowing base is scheduled to be redetermined in

August

of

2019

and thereafter in

March

and

September

of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent

may

request

one

unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower

may

also request the issuance of letters of credit under the

2019

Credit Agreement in an aggregate amount up to

$10

 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

All amounts outstanding under the

2019

Senior Credit Facility bear interest at a rate per annum equal to, at the Company’s option, either (i) the alternative base rate plus an applicable margin ranging from

1.50%

to

2.50%,

depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin from

2.50%

to

3.50%,

depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the

2019

Senior Credit Facility are subject to a commitment fee ranging from

0.375%

to

0.50%,

depending on the percentage of the borrowing base that is utilized. To the extent that a payment default exists and is continuing, all amounts outstanding under the

2019

Senior Credit Facility will bear interest at

2.0%

per annum above the rate and margin otherwise applicable thereto.

The obligations under the

2019

Credit Agreement are guaranteed by the Company and secured by a

first

lien security interest in substantially all of the assets of the Company and the Borrower.

The

2019

Credit Agreement contains certain customary representations and warranties, affirmative and negative covenants and events of default. If an event of default occurs and is continuing, the lenders

may

declare all amounts outstanding under the

2019

Senior Credit Facility to be immediately due and payable.

The

2019

Credit Agreement also contains certain financial covenants, including the maintenance of (i) a ratio of Net Funded Debt to EBITDAX

not

to exceed

4.00

to

1.00

as of the last day of any fiscal quarter, (ii) a current ratio (based on the ratio of current assets to current liabilities as defined in the

2019

Credit Agreement)

not

to be less than

1.00

to

1.00

and (iii) until

no

New

2L

Notes remain outstanding, a ratio of Total Proved PV-

10

 attributable to the Company’s and Borrower’s Proved Reserves to Total Secured Debt (net of any Unrestricted Cash

not

to exceed

$10

million)

not

to be less than

1.50

to

1.00

and minimum liquidity requirements.

On

May 14, 2019,

the Company utilized borrowings under the

2019

Senior Credit Facility to refinance its obligations under the

2017

Senior Credit Facility and to fund the Redemption (as defined below) of the Convertible Second Lien Notes.

As of 

June 30, 2019

, the Company had a borrowing base of

$115.0

million with

$84.4

million outstanding. The Company also had

$2.1

 million of unamortized debt issuance costs recorded as of 

June 30, 2019

related to the

2019

 Senior Credit Facility.

As of

June 30, 2019

, the Company was

in compliance with all covenants within the

2019

 Senior Credit Facility

.

Convertible Second Lien Notes

On

October 12, 2016,

the Company and the Subsidiary, entered into a purchase agreement with certain investors (collectively, and together with each of their successors and assigns, the “Purchasers”), in connection with the issuance of

$40.0

million aggregate principal amount of the Company’s

13.50%

Convertible Second Lien Senior Secured Notes due

2019

(the “Convertible Second Lien Notes”).

The aggregate principal amount of the Convertible Second Lien Notes was convertible at the option of the Purchasers at any time prior to the scheduled maturity date at

$21.33

per share representing

1.9

million shares of the Company's common stock, subject to adjustments. At closing, the Purchasers were issued

10

-year costless warrants to acquire

2.5

million shares of common stock. Holders of the Convertible Second Lien Notes had a

second

priority lien on all assets of the Company, and holders of such warrants had a right to appoint

two

members to our Board of Directors (the “Board”) as long as such warrants were outstanding.

The Convertible Second Lien Notes, as set forth in the agreement, were scheduled to mature on

August 30, 2019

or

six

months after the maturity of our current revolving credit facility but in

no

event later than

March 30, 2020.

The Convertible Second Lien Notes bore interest at the rate of

13.50%

 per annum, payable quarterly in arrears on

January 

15,

 

April 

15,

 

July 

15

and

October 

15

of each year. T

he Company also had the option under certain circumstances to pay all or any portion of interest in-kind on the then outstanding principal amount of the Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional

second

lien notes.

Upon issuance of the Convertible Second Lien Notes in

October 2016,

in accordance with accounting standards related to convertible debt instruments that

may

be settled in cash upon conversion as well as warrants on the debt instrument, we recorded a debt discount of

$11.0

million, thereby reducing the

$40.0

million carrying value upon issuance to

$29.0

million and recorded an equity component of

$11.0

million. The debt discount was amortized using the effective interest rate method based upon an original term through

August 

30,

2019.

The Convertible Second Lien Notes were paid off in full on

May 29, 2019

for

$56.7

million. In connection with the payoff of the Convertible Second Lien Notes, we recorded a

$1.6

million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs.

Redemption of Convertible Second Lien Notes

On

May 14, 2019,

the Company satisfied and discharged and called for redemption the Convertible Second Lien Notes by depositing funds equal to the redemption price plus interest on the Company’s approximately

$56.7

million aggregate principal amount of outstanding Convertible Second Lien Notes, and such notes were redeemed on

May 29, 2019.

The Company used borrowings under its

2019

Senior Credit Facility to fund the satisfaction, discharge and redemption of the Convertible Second Lien Notes.

New Convertible Second Lien Notes

 

On

May 14, 2019,

the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New

2L

Notes Purchaser”) pursuant to which the Company issued to the New

2L

Notes Purchasers (the “New

2L

Notes Offering”)

$12.0

million aggregate principal amount of the Company’s

13.50%

Convertible Second Lien Senior Secured Notes due

2021

(the “New

2L

Notes”). The closing of the New

2L

Notes Offering occurred on

May 31, 2019.

Proceeds from the sale of the New

2L

Notes were primarily used to pay down outstanding borrowings under the

2019

Senior Credit Facility. Holders of the New

2L

Notes have a

second

priority lien on all assets of the Company.

The New

2L

Notes, as set forth in the indenture governing such notes (the “New

2L

Notes Indenture”), are scheduled to mature on

May 31, 2021. 

The New

2L

Notes bear interest at the rate of

13.50%

 per annum, payable quarterly in arrears on

January 

15,

 

April 

15,

 

July 

15

and

October 

15

of each year. The Company

may

elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the New

2L

Notes by increasing the principal amount of the outstanding New

2L

Notes. 

The New

2L

Notes Indenture contains certain covenants pertaining to us and our Subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sales of assets and stock; business activities; transactions with affiliates; and changes of control. The New

2L

Notes Indenture also contains a financial covenant which requires the maintenance of a Total Proved Asset Coverage Ratio 

not

to be less than

1.50

to

1.00.

The New

2L

Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of New

2L

Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be

$21.33,

subject to certain adjustments as described in the New

2L

Notes Indenture. Upon conversion, the Company must deliver, at its option, either (

1

) a number of shares of its common stock determined as set forth in the New

2L

Notes Indenture, (

2

) cash or (

3

) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the New

2L

Notes with cash is subject to the terms of the

2019

Senior Credit Agreement.

The New

2L

Notes were issued and sold to the New

2L

Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of

1933,

as amended (the “Securities Act”), pursuant to Section

4

(a)(

2

) thereunder. The New

2L

Notes Purchasers

may

only resell the New

2L

Notes only to qualified institutional buyers in accordance with Rule

144A

under the Securities Act and to certain persons outside the United States in accordance with Regulation S under the Securities Act. The New

2L

Notes have

not

been registered under the Securities Act or applicable state securities laws and

may

not

be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws.

Upon issuance of the New

2L

 Notes on

May 31, 2019,

in accordance with accounting standards related to convertible debt instruments that

may

be settled in cash upon conversion, we recorded a debt discount of

$1.4

million, thereby reducing the

$12.0

million carrying value upon issuance to

$10.6

million and recorded an equity component of

$1.4

million. The equity component was valued using a binomial model. The debt discount is amortized using the effective interest rate method based upon an original term through

May 31, 2021.

As of 

June 30, 2019

,

$1.4

million of debt discount and

$0.2

million of debt issuance costs remained to be amortized on the New

2L

Notes.

As of 

June 30, 2019

, the Company was in compliance with all covenants within the New

2L

Notes Indenture.

XML

Note 5 - Equity

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Stockholders' Equity Note Disclosure [Text Block]

NOTE

5—Equity

During the

three

and

six

months ended

June 30, 2019

,

150,000

of the

10

-year costless warrants associated with the Convertible Second Lien Notes were exercised. The Company received cash for the

one

cent par value for the issuance of the

150,000

common shares. As of

June 30, 2019

,

no

such warrants remain un-exercised. The Company did

not

have a material vesting of its share-based compensation units during the

three

or

six

months ended

June 30, 2019

.

In connection with the issuance of the New

2L

Notes, we recorded an equity component of

$1.4

million. For further details, see

Note

4

.

During the

three

months ended

June 30, 2018,

certain holders of the

10

-year costless warrants associated with the Convertible Second Lien Notes exercised

273,437

warrants for the issuance of an equal amount of our

one

cent par value common stock. The Company received cash for the

one

cent par value for the issuance of

273,437

common shares. During the

six

months ended

June 30, 2018,

certain holders of the

10

-year costless warrants associated with the Convertible Second Lien Notes exercised

862,812

warrants for the issuance of an equal amount of our

one

cent par value common stock. The Company received cash for th

e

one

cent par value for the issuance of

315,937

common shares. As of

June 30, 2018,

207,500

of such warrants remain un-exercised. The Company did

not

have a material vesting of its share-based compensation units during the 

three

or

six

months ended

June 30, 2018

.

XML

Note 6 - Net Income (Loss) Per Common Share

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Earnings Per Share [Text Block]

NOTE

6—Net

Income (Loss) Per Common Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted net income (loss) per common share for the 

three

and

six

months ended

June 30, 2019

and

2018

. The Company used the treasury stock method in determining the effects of potentially dilutive restricted stock. The following table sets forth information related to the computations of basic and diluted net income (loss) per common share:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(Amounts in thousands, except per share data)
Basic net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Basic net income (loss) per common share	$	0.96	$	(0.23	)	$	1.00	$	(0.70	)
Diluted net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Interest, discount and amortization on New 2L Notes		107		-			107		-
Adjusted net income (loss) per common share	$	11,886	$	(2,661	)	$	12,334	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Common shares issuable upon conversion of the New 2L Notes		569		-			569		-
Common shares issuable upon conversion of warrants of unsecured claim holders		1,282		-			1,282		-
Common shares issuable on assumed conversion of restricted stock (4)		519		-			466		-
Diluted weighted average shares of common stock outstanding		14,581		11,629			14,498		11,424
Diluted net income (loss) per common share (1) (2) (3)	$	0.82	$	(0.23	)	$	0.85	$	(0.70	)
(1) Common shares issuable on assumed conversion of share-based compensation for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. (4)		-		491			-		346
(2) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,875			-		1,875
(3) Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,642			-		1,642

(

4

) Common shares issuable on assumed conversion of share-based compensation assumes a payout of the Company's performance share awards at

100%

of the initial units granted (or a ratio of

one

unit to

one

common share). The range of common stock shares which

may

be earned ranges from

zero

to

250%

of the initial performance units granted.

XML

Note 7 - Income Taxes

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Income Tax Disclosure [Text Block]

NOTE

7—Income

Taxes

We record

ed

no

income tax expense or benefit for either the 

three

or

six

months ended

June 30, 2019

or

2018

. We recorded a valuation allowance for our net deferred tax asset at

December 31, 2016.

We recorded this valuation allowance at this date after an evaluation of all available evidence (including our history of net operating losses) that led to a conclusion that based upon the more-likely-than-

not

standard of the accounting literature, these deferred tax assets were unrecoverable.

The valuation allowance was

$84.1

 million as of 

December 31, 2018

, which resulted in a net non-current deferred tax asset of

$0.8

 million appearing on our statement of financial position. The net

$0.8

million deferred tax asset relates to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years

2018

-

2021

regardless of the Company's regular tax liability. Considering the Company’s taxable income forecasts, our assessment of the realization of our deferred tax assets has

not

changed, and we continue to maintain a full valuation allowance for our net deferred tax assets as of 

June 30, 2019

aside from the deferred tax asset related to the AMT credits.

As of

June 30, 2019

, we have

no

unrecognized tax benefits. There were

no

significant changes to our tax position since

December 31, 2018

.

XML

Note 8 - Commodity Derivative Activities

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Derivative Instruments and Hedging Activities Disclosure [Text Block]

NOTE

8—Commodity

Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices. We are currently

not

designating our derivative contracts for hedge accounting. All derivative gains and losses are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.

The following table summarizes gains and losses we recognized on our oil and natural gas derivatives for the

three

and

six

months ended

June 30, 2019

and

2018

:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Oil and Natural Gas Derivatives (in thousands)
Gain (loss) on commodity derivatives not designated as hedges, settled	$	1,973	$	(156	)	$	213	$	(541	)
Gain (loss) on commodity derivatives not designated as hedges, not settled		10,680		(2,018	)		11,432		(2,614	)
Total gain (loss) on commodity derivatives not designated as hedges	$	12,653	$	(2,174	)	$	11,645	$	(3,155	)

Commodity Derivative Activity

We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all derivatives are approved by the Hedging Committee of our Board, and reviewed periodically by the Board.

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Decreases in domestic crude oil and natural gas spot prices will have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counter-parties. Neither our counter-parties nor we require any collateral upon entering into derivative contracts. We would have been at risk

of losing

$12.1

 million had SunTrust Bank and RBC Capital Markets been unable to fulfill their obligations as of

June 30, 2019

.

As of

June 30, 2019

, the open positions on our outstanding commodity derivative contracts, all of which were with SunTrust Bank an

d RBC Capital Markets, wer

e as follows:

Contract Type	Average Daily Volume		Total Volume		Weighted Average Fixed Price		Fair Value at June 30, 2019 (In thousands)
Oil swaps (Bbls)
2019		300		55,200	$	51.08	$	(376	)
2020		221		80,945	$	59.02		243
2021 (through March 31, 2021)		200		18,000	$	56.58		37
Total oil							$	(96	)
Natural Gas swaps (MMBtu)
2019		100,000		18,400,000	$	2.887	$	9,587
2020		33,344		12,204,000	$	2.756		2,155
2021 (through March 31, 2021)		16,656		1,499,000	$	2.862		118
Total natural gas							$	11,860
Total oil and natural gas							$	11,764

During the

second

quarter of

2019

 we entered into the following contracts with RBC Capital Markets:

Contract Type	Average Daily Volume		Weighted Average Fixed Price		Contract Start Date	Contract Termination
Natural gas swap (MMBtu)		20,090	$	2.677	April 1, 2020	March 31, 2021
Oil swap (Bbls)		217	$	58.57	January 1, 2020	March 31, 2021

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of 

June 30, 2019

(in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See

Note

1—“Description

of Business and Significant Accounting Policies”

for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.

Description	Level 1		Level 2			Level 3		Total
Fair value of oil and natural gas derivatives - Current Assets	$	-	$	11,421		$	-	$	11,421
Fair value of oil and natural gas derivatives - Non-current Assets		-		719			-		719
Fair value of oil and natural gas derivatives - Current Liabilities		-		(376	)		-		(376	)
Fair value of oil and natural gas derivatives - Non-current Liabilities		-		-			-		-
Total	$	-	$	11,764		$	-	$	11,764

We enter into oil and natural gas derivative contracts under which we have netting arrangements with each counter-party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance Sheets as of 

June 30, 2019

and

December 31, 2018

:

	June 30, 2019								December 31, 2018
Fair Value of Oil and Natural Gas Derivatives	Gross			Amount		As			Gross			Amount			As
(in thousands)	Amount			Offset		Presented			Amount			Offset			Presented
Fair value of oil and natural gas derivatives - Current Assets	$	11,421		$	-	$	11,421		$	2,893		$	(2,090	)	$	803
Fair value of oil and natural gas derivatives - Non-current Assets		719			-		719			-			-			-
Fair value of oil and natural gas derivatives - Current Liabilities		(376	)		-		(376	)		(2,090	)		2,090			-
Fair value of oil and natural gas derivatives - Non-current Liabilities		-					-			(471	)		-			(471	)
Total	$	11,764		$	-	$	11,764		$	332		$	-		$	332

XML

Note 9 - Commitments and Contingencies

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

NOTE

9—Commitments

and Contingencies

We are party to various lawsuits from time to time arising in the normal course of business, including, but

not

limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, would

not

have been material to our consolidated financial position, results of operations or liquidity for the 

three

and

six

months ended

June 30, 2019

 and

2018

.

XML

Note 10 - Leases

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Lessee, Operating Leases [Text Block]

NOTE

10—Leases

We adopted ASU

2016

-

02,

Leases

, during the quarter ended

March 31, 2019,

and we elected the transition relief package of practical expedients. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of

12

months or less are

not

recorded on our Consolidated Balance Sheets. We lease our corporate office building in Houston, Texas. We recognize lease expense for this lease on a straight-line basis over the lease term. This operating lease is included in furniture, fixtures and equipment and other capital assets, accrued liabilities and other non-current liabilities on our Consolidated Balance Sheets. The operating lease asset and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term. As this lease did

not

provide an implicit rate, we used a collateralized incremental borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease asset includes any lease payments made but excludes annual operating charges. Operating lease expense is recognized on a straight-line basis over the lease term and reported in general and administrative operating expense on our Consolidated Statements of Operations. We have also entered into leases for certain vehicles and other equipment which are immaterial to our financial statements and have therefore

not

been recorded on our Consolidated Balance Sheets.

The lease cost components for the

three

and

six

months ended

June 30, 2019

 are classified as follows:

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Consolidated Statements of Operations Classification
Building lease cost	$	403	$	756	General and administrative expense
Variable lease cost (1)		48		95	General and administrative expense
	$	451	$	851

(

1

) Includes building operating expenses.

The following are additional details related to our lease portfolio as of

June 30, 2019

:

(in thousands)	June 30, 2019			Consolidated Balance Sheets Classification
Lease asset, gross	$	2,922		Furniture, fixtures and equipment and other capital assets
Accumulated depreciation		(626	)	Accumulated depletion, depreciation and amortization
Lease asset, net	$	2,296
Current lease liability	$	1,359		Accrued liabilities
Non-current lease liability		1,523		Other non-current liabilities
Total lease liabilities	$	2,882

The following table presents operating lease liability maturities as of

June 30, 2019

:

(in thousands)	June 30, 2019
2019	$	770
2020		1,540
2021		813
2022		-
2023		-
Thereafter		-
Total lease payments	$	3,123
Less imputed interest		241
Present value of lease liabilities	$	2,882

The future minimum obligations under operating leases in effect as of

December 31, 2018

having a noncancelable term in excess of

one

year as determined prior to the adoption of ASU

842

are as follows:

(in thousands)	December 31, 2018
2019	$	3,753
2020		1,556
2021		513
2022		-
2023		-
Thereafter		-
Future minimum lease obligations	$	5,822

As of

June 30, 2019

, our office building operating lease has a weighted-average remaining lease term

of

1.8

years and

a weighted-average discount rate of

8.0

percent. Cash paid for amounts included in the measurement of operating lease liabilities was

$0.4

 million and

$0.8

 million for the 

three

and

six

months ended

June 30, 2019

, respectively.

XML

Note 11 - Dispositions

6 Months Ended

Jun. 30, 2019

Notes to Financial Statements

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

NOTE

11—Dispositions

On

March 1, 2019,

the Company closed on the sale of working interests in certain non-core Haynesville Shale Trend oil and gas leases and related facilities in Caddo Parish, Louisiana for total consideration of

$1.3

million, subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheets.

On

May 21, 2018,

the Company closed on the sale of working interests in certain oil and gas leases, including wells, facilities and leasehold acres, in our Tuscaloosa Marine Shale Trend operating area located in East and West Feliciana Parish, Louisiana for total consideration of approximately

$3.3

million with an effective date of

May 1, 2018.

The disposition was subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet.

On

February 28, 2018,

the Company closed, in

two

separate transactions, the sale of working interests in certain oil and gas leases, wells, units and facilities and certain net leasehold interests in a portion of its undeveloped acreage in the Angelina River Trend in Angelina and Nacogdoches Counties, Texas to BP America Production Company for total consideration of

$23.0

million, with an effective date of

January 1, 2018.

The disposition was subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet. The Company utilized the proceeds from these dispositions to pay down the outstanding balance of the

2017

Senior Credit Facility on

March 2, 2018

and to fund our capital expenditures program.

The Company also sold other miscellaneous acreage during the

three

and

six

months ended

June 30, 2018

for

$0.4

million and

$0.7

million, respectively, which was also recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheet.

XML

Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The consolidated financial statements of the Company included in this Quarterly Report on Form

10

-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and accordingly, certain information normally included in financial statements prepared in accordance with United States Generally Accepted Accounting Principles (“US GAAP”) has been condensed or omitted. This information should be read in conjunction with our consolidated financial statements and notes contained in our annual report on Form

10

-K for the year ended 

December 31, 2018

. Operating results for the 

three

and

six

months ended

June 30, 2019

are

not

necessarily indicative of the results that

may

be expected for the full year or for any interim period.

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

—The consolidated financial statements include the financial statements of the Company and the Subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

— Our management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

—Cash and cash equivalents includes cash on hand, demand deposit accounts and temporary cash investments with maturities of

ninety

days or less at the date of purchase.

Accounts Payable, Policy [Policy Text Block]

Accounts Payable

—Accounts payable consisted of the following amounts as of 

June 30, 2019

and 

December 31, 2018

:

(In thousands)	June 30, 2019		December 31, 2018
Trade payables	$	14,317	$	8,633
Revenue payables		21,057		16,665
Prepayments from partners		293		132
Miscellaneous payables		230		304
Total Accounts payable	$	35,897	$	25,734

Accrued Liabilities, Policy [Policy Text Block]

Accrued Liabilities

—Accrued liabilities consisted of the following amounts as of 

June 30, 2019

and 

December 31, 2018

:

(In thousands)	June 30, 2019		December 31, 2018
Accrued capital expenditures	$	7,067	$	8,086
Accrued lease operating expense		936		1,100
Accrued production and other taxes		704		338
Accrued transportation and gathering		2,860		1,888
Accrued performance bonus		1,943		3,420
Accrued interest		216		443
Accrued office lease		1,359		598
Accrued general and administrative expense and other		959		645
Total Accrued liabilities	$	16,044	$	16,518

Inventory, Policy [Policy Text Block]

Inventory

—Inventory consists of casing and tubulars that are expected to be used in our capital drilling program. Inventory is carried on the Consolidated Balance Sheets at the lower of cost or market.

Property, Plant and Equipment, Policy [Policy Text Block]

Property and Equipment

—Under US GAAP,

two

acceptable methods of accounting for oil and natural gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of oil and natural gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the

two

methods are in the treatment of exploration costs, the computation of depreciation, depletion and amortization (“DD&A”) expense and the assessment of impairment of oil and natural gas properties. We have elected to adopt the Full Cost Method of accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method better reflects the true economics of exploring for and developing our oil and gas reserves.

Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, but do

not

include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and natural gas properties and thereby subject to DD&A and the full cost ceiling test. For the

three

months ended

June 30, 2019

and

2018

, we transferred

$0.1

million and

$0.3

 million, respectively, 

from unevaluated properties to proved oil and natural gas properties. For the 

six

months ended

June 30, 2019

and

2018

, we transferred

$0.2

million and

$0.4

million, respectively, 

from unevaluated properties to proved oil and natural gas properties. Our sales of oil and natural gas properties are accounted for as adjustments to net proved oil and natural gas properties with

no

gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods' production also converted to Mcfe to arrive at the periods' DD&A expense.

Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from

three

to

five

years.

Full Cost or Successful Efforts, Policy [Policy Text Block]

Full Cost Ceiling Test

—The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and natural gas properties, net of related deferred taxes. This comparison is referred to as a “ceiling test”. If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted future net cash flows from proved

reserves, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a

12

-month average pricing assumption.

There were

no

Full Cost Ceiling Test write-downs for the

three

or

six

months ended

June 30, 2019

or

2018

.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurement

—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of non-performance, which includes, among other things, our credit risk.

We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value

may

be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into

three

levels (levels

1,

2

and

3

) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels and our corresponding instruments classified by level are further described below:

• Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;

• Level 2 Inputs— quotes that are derived principally from or corroborated by observable market data. Included in this level are our 2017 Senior Credit Facility and 2019 Senior Credit Facility (both as defined below) and commodity derivatives whose fair values are based on third -party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counter-parties; and

• Level 3 Inputs— unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this level would be our initial measurement of asset retirement obligations.

As of

June 30, 2019

and

December 31, 2018

, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

Asset Retirement Obligation [Policy Text Block]

Asset Retirement Obligations

—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and natural gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations. See

Note

3

.

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligations was classified as Level

3

in the fair value hierarchy.

Revenue from Contract with Customer [Policy Text Block]

Revenue Recognition

—Oil and natural gas revenues are generally recognized upon delivery of our produced oil and natural gas volumes to our customers. We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales

may

not

be received for up to

60

days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record a liability or an asse

t for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. As of

June 30, 2019

and

December 31, 2018

, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted. See

Note

2

.

Derivatives, Policy [Policy Text Block]

Derivative Instruments

—We use derivative instr

uments such as swaps, collars, futures, forwards and options for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counter-party for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All of our realized gain or losses on our derivative contracts are the result of cash settlements. We have

not

designated any of our derivative contracts as hedges; accordingly, changes in fair value are reflected in earnings. See

Note

8

.

Income Tax, Policy [Policy Text Block]

Income Taxes

—We account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than

not

that some portion or all of the deferred tax assets will

not

be realized.

We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than

not

sustain the position following an audit. For tax positions meeting the more likely-than-

not

threshold, the amount recognized in the financial statements is the largest benefit that has a greater than

50

percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See

Note

7

.

Earnings Per Share, Policy [Policy Text Block]

Net Income or Net Loss Per Common Share—

Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted-average shares of common stock outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted average shares of common stock outstanding during the period, plus the effects of potentially dilutive restricted stock calculated using the treasury stock method and the potential dilutive effect of the conversion of convertible securities, such as warrants and convertible notes, into shares of our common stock. See

Note

6

.

Commitments and Contingencies, Policy [Policy Text Block]

Commitments and Contingencies

—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from

third

parties, when probable of realization, are separately recorded and are

not

offset against the related environmental liability. See

Note

9

.

Share-based Payment Arrangement [Policy Text Block]

Share-Based Compensation

—We account for our share-based transactions using the fair value as of the grant date and recognize compensation expense over the requisite service period.

Guarantee, Policy [Policy Text Block]

Guarantee

—As of

June 30, 2019

, Goodrich Petroleum Company LLC, the wholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our New

2L

Notes (as defined below).

Debt, Policy [Policy Text Block]

Debt Issuance Cost

—The Company records debt issuance costs associated with its New

2L

Notes (and previously with its Convertible Second Lien Notes, both as defined below) as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the life of the respective notes. Debt issuance costs associated with our revolving credit facility debt are recorded in other assets in our Consolidated Balance Sheets, which is amortized straight-line over the life of such debt.

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

On

August 28, 2018,

the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”)

2018

-

13,

Fair Value Measurements (Topic

820

): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“Topic

820”

). The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic

820

including the removal, modification and addition of certain disclosure requirements. For all entities, the amendments in this ASU are effective for fiscal periods beginning after

December 15, 2019,

including interim periods therein. We are evaluating the expected impact these amendments will have on our consolidated financial statements.

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Note 1 - Description of Business and Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]

(In thousands)	June 30, 2019		December 31, 2018
Trade payables	$	14,317	$	8,633
Revenue payables		21,057		16,665
Prepayments from partners		293		132
Miscellaneous payables		230		304
Total Accounts payable	$	35,897	$	25,734

(In thousands)	June 30, 2019		December 31, 2018
Accrued capital expenditures	$	7,067	$	8,086
Accrued lease operating expense		936		1,100
Accrued production and other taxes		704		338
Accrued transportation and gathering		2,860		1,888
Accrued performance bonus		1,943		3,420
Accrued interest		216		443
Accrued office lease		1,359		598
Accrued general and administrative expense and other		959		645
Total Accrued liabilities	$	16,044	$	16,518

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Note 2 - Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Disaggregation of Revenue [Table Text Block]

	Three Months Ended June 30, 2019								Six Months Ended June 30, 2019
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	2,805	$	25,163	$	-	$	27,968	$	5,516	$	45,337	$	-	$	50,853
Non-operated		139		3,775		4		3,918		214		9,957		8		10,179
Total oil and natural gas revenues	$	2,944	$	28,938	$	4	$	31,886	$	5,730	$	55,294	$	8	$	61,032

	Three Months Ended June 30, 2018								Six Months Ended June 30, 2018
(In thousands)	Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues		Oil Revenue		Gas Revenue		NGL Revenue		Total Oil and Natural Gas Revenues
Operated	$	3,835	$	10,900	$	-	$	14,735	$	7,634	$	16,701	$	-	$	24,335
Non-operated		133		2,912		4		3,049		276		5,008		8		5,292
Total oil and natural gas revenues	$	3,968	$	13,812	$	4	$	17,784	$	7,910	$	21,709	$	8	$	29,627

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Note 3 - Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Schedule of Asset Retirement Obligations [Table Text Block]

	Six Months Ended June 30, 2019
Beginning balance as of December 31, 2018	$	3,791
Liabilities incurred		82
Liabilities settled		(3	)
Dispositions		(53	)
Accretion expense		146
Ending balance as of June 30, 2019	$	3,963
Current liability	$	-
Long term liability	$	3,963

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Note 4 - Debt (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Schedule of Long-term Debt Instruments [Table Text Block]

	June 30, 2019				December 31, 2018
	Principal		Carrying Amount		Principal		Carrying Amount
2017 Senior Credit Facility	$	-	$	-	$	27,000	$	27,000
2019 Senior Credit Facility		84,400		84,400		-		-
Convertible Second Lien Notes (1)		-		-		53,691		49,820
New 2L Notes (2)		12,135		10,504		-		-
Total debt	$	96,535	$	94,904	$	80,691	$	76,820

Schedule of Interest Expense and Effective Interest on Liability Component [Table Text Block]

	Three Months Ended June 30, 2019					Three Months Ended June 30, 2018					Six Months Ended June 30, 2019					Six Months Ended June 30, 2018
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
2017 Senior Credit Facility	$	364		8.2	%	$	75	*			$	872		7.2	%	$	248		7.8	%
2019 Senior Credit Facility		695		5.9	%		-		-			695		5.9	%		-		-
Convertible Second Lien Notes (1)		2,155		23.9	%		2,657		24.7	%		5,304		24.1	%		5,157		24.8	%
New 2L Notes (2)		184		20.5	%		-		-			184		20.5	%		-		-
Total interest expense	$	3,398				$	2,732				$	7,055				$	5,405

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Note 6 - Net Income (Loss) Per Common Share (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(Amounts in thousands, except per share data)
Basic net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Basic net income (loss) per common share	$	0.96	$	(0.23	)	$	1.00	$	(0.70	)
Diluted net income (loss) per common share:
Net income (loss) applicable to common stock	$	11,779	$	(2,661	)	$	12,227	$	(7,985	)
Interest, discount and amortization on New 2L Notes		107		-			107		-
Adjusted net income (loss) per common share	$	11,886	$	(2,661	)	$	12,334	$	(7,985	)
Weighted average shares of common stock outstanding		12,211		11,629			12,181		11,424
Common shares issuable upon conversion of the New 2L Notes		569		-			569		-
Common shares issuable upon conversion of warrants of unsecured claim holders		1,282		-			1,282		-
Common shares issuable on assumed conversion of restricted stock (4)		519		-			466		-
Diluted weighted average shares of common stock outstanding		14,581		11,629			14,498		11,424
Diluted net income (loss) per common share (1) (2) (3)	$	0.82	$	(0.23	)	$	0.85	$	(0.70	)
(1) Common shares issuable on assumed conversion of share-based compensation for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. (4)		-		491			-		346
(2) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,875			-		1,875
(3) Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.		-		1,642			-		1,642

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Note 8 - Commodity Derivative Activities (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Schedule of Realized and Unrealized Gains and Losses [Table Text Block]

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Oil and Natural Gas Derivatives (in thousands)
Gain (loss) on commodity derivatives not designated as hedges, settled	$	1,973	$	(156	)	$	213	$	(541	)
Gain (loss) on commodity derivatives not designated as hedges, not settled		10,680		(2,018	)		11,432		(2,614	)
Total gain (loss) on commodity derivatives not designated as hedges	$	12,653	$	(2,174	)	$	11,645	$	(3,155	)

Schedule of Price Risk Derivatives [Table Text Block]

Contract Type	Average Daily Volume		Total Volume		Weighted Average Fixed Price		Fair Value at June 30, 2019 (In thousands)
Oil swaps (Bbls)
2019		300		55,200	$	51.08	$	(376	)
2020		221		80,945	$	59.02		243
2021 (through March 31, 2021)		200		18,000	$	56.58		37
Total oil							$	(96	)
Natural Gas swaps (MMBtu)
2019		100,000		18,400,000	$	2.887	$	9,587
2020		33,344		12,204,000	$	2.756		2,155
2021 (through March 31, 2021)		16,656		1,499,000	$	2.862		118
Total natural gas							$	11,860
Total oil and natural gas							$	11,764

Contract Type	Average Daily Volume		Weighted Average Fixed Price		Contract Start Date	Contract Termination
Natural gas swap (MMBtu)		20,090	$	2.677	April 1, 2020	March 31, 2021
Oil swap (Bbls)		217	$	58.57	January 1, 2020	March 31, 2021

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Description	Level 1		Level 2			Level 3		Total
Fair value of oil and natural gas derivatives - Current Assets	$	-	$	11,421		$	-	$	11,421
Fair value of oil and natural gas derivatives - Non-current Assets		-		719			-		719
Fair value of oil and natural gas derivatives - Current Liabilities		-		(376	)		-		(376	)
Fair value of oil and natural gas derivatives - Non-current Liabilities		-		-			-		-
Total	$	-	$	11,764		$	-	$	11,764

Offsetting Liabilities [Table Text Block]

	June 30, 2019								December 31, 2018
Fair Value of Oil and Natural Gas Derivatives	Gross			Amount		As			Gross			Amount			As
(in thousands)	Amount			Offset		Presented			Amount			Offset			Presented
Fair value of oil and natural gas derivatives - Current Assets	$	11,421		$	-	$	11,421		$	2,893		$	(2,090	)	$	803
Fair value of oil and natural gas derivatives - Non-current Assets		719			-		719			-			-			-
Fair value of oil and natural gas derivatives - Current Liabilities		(376	)		-		(376	)		(2,090	)		2,090			-
Fair value of oil and natural gas derivatives - Non-current Liabilities		-					-			(471	)		-			(471	)
Total	$	11,764		$	-	$	11,764		$	332		$	-		$	332

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Note 10 - Leases (Tables)

6 Months Ended

Jun. 30, 2019

Notes Tables

Lease, Cost [Table Text Block]

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Consolidated Statements of Operations Classification
Building lease cost	$	403	$	756	General and administrative expense
Variable lease cost (1)		48		95	General and administrative expense
	$	451	$	851

Operating Lease, Assets and Liabilities [Table Text Block]

(in thousands)	June 30, 2019			Consolidated Balance Sheets Classification
Lease asset, gross	$	2,922		Furniture, fixtures and equipment and other capital assets
Accumulated depreciation		(626	)	Accumulated depletion, depreciation and amortization
Lease asset, net	$	2,296
Current lease liability	$	1,359		Accrued liabilities
Non-current lease liability		1,523		Other non-current liabilities
Total lease liabilities	$	2,882

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

(in thousands)	June 30, 2019
2019	$	770
2020		1,540
2021		813
2022		-
2023		-
Thereafter		-
Total lease payments	$	3,123
Less imputed interest		241
Present value of lease liabilities	$	2,882

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

(in thousands)	December 31, 2018
2019	$	3,753
2020		1,556
2021		513
2022		-
2023		-
Thereafter		-
Future minimum lease obligations	$	5,822

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Note 1 - Description of Business and Significant Accounting Policies (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Oil and Gas Property Full Cost Method Period Increase (Decrease)	$ 100	$ 300	$ 200	$ 400
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense	$ 0	$ 0	$ 0	$ 0
Minimum [Member]
Property, Plant and Equipment, Useful Life			3 years
Maximum [Member]
Property, Plant and Equipment, Useful Life			5 years

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Note 1 - Description of Business and Significant Accounting Policies - Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Trade payables	$ 14,317	$ 8,633
Revenue payables	21,057	16,665
Prepayments from partners	293	132
Miscellaneous payables	230	304
Total Accounts payable	35,897	25,734
Accrued capital expenditures	7,067	8,086
Accrued lease operating expense	936	1,100
Accrued production and other taxes	704	338
Accrued transportation and gathering	2,860	1,888
Accrued performance bonus	1,943	3,420
Accrued interest	216	443
Accrued office lease	1,359	598
Accrued general and administrative expense and other	959	645
Total Accrued liabilities	$ 16,044	$ 16,518

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Note 2 - Revenue Recognition (Details Textual) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Accrued Oil and Gas Revenue	$ 15,869	$ 14,464

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Note 2 - Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenue from Contract with Customer	$ 31,884	$ 17,835	$ 61,024	$ 29,669
Oil Revenue [Member]
Revenue from Contract with Customer	2,944	3,968	5,730	7,910
Oil Revenue [Member] | Operated [Member]
Revenue from Contract with Customer	2,805	3,835	5,516	7,634
Oil Revenue [Member] | Non-operated [Member]
Revenue from Contract with Customer	139	133	214	276
Gas Revenue [Member]
Revenue from Contract with Customer	28,938	13,812	55,294	21,709
Gas Revenue [Member] | Operated [Member]
Revenue from Contract with Customer	25,163	10,900	45,337	16,701
Gas Revenue [Member] | Non-operated [Member]
Revenue from Contract with Customer	3,775	2,912	9,957	5,008
NGL Revenue [Member]
Revenue from Contract with Customer	4	4	8	8
NGL Revenue [Member] | Operated [Member]
Revenue from Contract with Customer
NGL Revenue [Member] | Non-operated [Member]
Revenue from Contract with Customer	4	4	8	8
Oil and Gas [Member]
Revenue from Contract with Customer	31,886	17,784	61,032	29,627
Oil and Gas [Member] | Operated [Member]
Revenue from Contract with Customer	27,968	14,735	50,853	24,335
Oil and Gas [Member] | Non-operated [Member]
Revenue from Contract with Customer	$ 3,918	$ 3,049	$ 10,179	$ 5,292

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Note 3 - Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Balance	$ 3,791
Liabilities incurred	82
Liabilities settled	(3)
Dispositions	(53)
Accretion expense	146
Balance	3,963
Current liability	0
Long term liability	$ 3,963	$ 3,791

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Note 4 - Debt (Details Textual) $ / shares in Units, $ in Thousands, shares in Millions							3 Months Ended				6 Months Ended
		May 31, 2019 USD ($) $ / shares	May 29, 2019 USD ($)	May 14, 2019 USD ($)	Oct. 17, 2017	Oct. 12, 2016 USD ($) $ / shares shares	Jun. 30, 2019 USD ($)		Jun. 30, 2018 USD ($)		Jun. 30, 2019 USD ($)		Jun. 30, 2018 USD ($)	Oct. 11, 2019 USD ($)	May 30, 2019 USD ($)	May 07, 2019 $ / shares	Dec. 31, 2018 USD ($)
Debt Instrument, Interest Rate During Period
Gain (Loss) on Extinguishment of Debt, Total							$ (1,846)				$ (1,846)
Debt Instrument, Face Amount							96,535				96,535						$ 80,691
Long-term Debt, Gross							94,904				94,904						76,820	[1]
Costless Warrants Associated with the Convertible Second Lien Notes [Member]
Warrants and Rights Outstanding, Term						10 years
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares						2.5
New Convertible Second Lien Notes, New 2L Notes [Member]
Long-term Debt Gross Paid in Kind Interest							100				100
Debt Instrument, Unamortized Discount, Total		$ 1,400					$ 1,400				$ 1,400
Debt Instrument, Interest Rate, Stated Percentage		13.50%					13.50%				13.50%
Debt Instrument, Interest Rate During Period							20.50%				20.50%
Debt Instrument, Covenant, Compliance Total Proved Asset Coverage Ratio		1.5
Debt Issuance Costs, Net, Total							$ 200				$ 200
Debt Instrument, Face Amount		$ 12,000					12,135	[2]			12,135	[2]						[2]
Debt Instrument, Convertible, Conversion Price | $ / shares		$ 21.33														$ 2
Long-term Debt, Gross		$ 10,600					10,504	[2]			10,504	[2]			$ 12,000			[2]
Debt Instrument, Convertible, Carrying Amount of Equity Component		1,400	$ 1,400
New Convertible Second Lien Notes, New 2L Notes [Member] | Maximum [Member]
Amortization of Debt Discount (Premium)							100				100
Paid-in-Kind Interest							$ 100				$ 100
Convertible Second Lien Notes [Member]
Debt Instrument, Unamortized Discount, Total						$ 11,000
Debt Instrument, Interest Rate, Stated Percentage						13.50%			13.50%				13.50%
Debt Instrument, Interest Rate During Period	[3]						23.90%		24.70%		24.10%		24.80%
Amortization of Debt Discount (Premium)							$ 900		$ 1,000		$ 2,300		$ 1,800
Paid-in-Kind Interest							1,200		$ 1,600		3,000		$ 3,200
Gain (Loss) on Extinguishment of Debt, Total		$ (1,600)
Debt Instrument, Face Amount						$ 40,000		[1]				[1]					53,691	[1]
Debt Instrument, Convertible, Conversion Price | $ / shares						$ 21.33
Debt Instrument, Convertible, Number of Equity Instruments						1,900,000
Long-term Debt, Gross						$ 29,000		[1]				[1]		$ 40,000			49,820	[1]
Adjustments to Additional Paid in Capital, Convertible Debt with Conversion Feature						$ 11,000
Debt Conversion, Original Debt, Amount			$ 56,700
The 2017 Senior Credit Facility [Member]
Debt Instrument, Interest Rate During Period							8.20%			[4]	7.20%		7.80%
Line of Credit Facility, Maximum Borrowing Capacity				$ 250,000
Line of Credit Facility, Current Borrowing Capacity				75,000
Line of Credit Facility, Commitment Fee Percentage					0.50%
Gain (Loss) on Extinguishment of Debt, Total				(200)
Debt Instrument, Face Amount																	27,000
Long-term Debt, Gross																	27,000
The 2017 Senior Credit Facility [Member] | Maximum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate					2.75%
The 2017 Senior Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate					3.75%
The 2017 Senior Credit Facility [Member] | Minimum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
The 2017 Senior Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate					2.75%
The 2019 Senior Credit Facility [Member]
Debt Instrument, Interest Rate During Period							5.90%				5.90%
Line of Credit Facility, Maximum Borrowing Capacity				500,000
Line of Credit Facility, Current Borrowing Capacity				$ 115,000			$ 115,000				$ 115,000
Line of Credit Facility, Interest Rate at Period End, Default Rate				2.00%
Debt Instrument, Covenant Compliance Debt to EBITDAX				4
Debt Instrument, Covenant, Current Ratio				1
Debt Instrument, Covenant Compliance Unrestricted Cash, Maximum				$ 10,000
Debt Instrument, Covenant, Compliance Total Proved Asset Coverage Ratio				1.5
Long-term Line of Credit, Total							84,400				84,400
Debt Issuance Costs, Net, Total							2,100				2,100
Debt Instrument, Face Amount							84,400				84,400
Long-term Debt, Gross							$ 84,400				$ 84,400
The 2019 Senior Credit Facility [Member] | Letter of Credit [Member]
Line of Credit Facility, Maximum Borrowing Capacity				$ 10,000
The 2019 Senior Credit Facility [Member] | Maximum [Member]
Line of Credit Facility, Commitment Fee Percentage				0.50%
The 2019 Senior Credit Facility [Member] | Maximum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate				2.50%
The 2019 Senior Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate				3.50%
The 2019 Senior Credit Facility [Member] | Minimum [Member]
Line of Credit Facility, Commitment Fee Percentage				0.375%
The 2019 Senior Credit Facility [Member] | Minimum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate				1.50%
The 2019 Senior Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate				2.50%

[1] The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019.

[2] The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2021. The principal included $0.1 million of accrued interest to be paid in-kind as of June 30, 2019. The carrying value included $1.4 million of unamortized debt discount as of June 30, 2019.

[3] The Convertible Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 23.9% and 24.1%, respectively, for the three and six months ended June 30, 2019 and 24.7% and 24.8%, respectively, for the three and six months ended June 30, 2018. Interest expense for the three months ended June 30, 2019 included $0.9 million of debt discount amortization and $1.2 million of paid in-kind interest, and interest expense for the three months ended June 30, 2018 included $1.0 million of debt discount amortization and $1.6 million of paid in-kind interest. Interest expense for the six months ended June 30, 2019 included $2.3 million of debt discount amortization and $3.0 million of paid in-kind interest, and interest expense for the six months ended June 30, 2018 included $1.8 million of debt discount amortization and $3.2 million of paid in-kind interest.

[4] Not meaningful due to the timing of borrowings during the three months ended June 30, 2018.

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Note 4 - Debt - Components of Debt (Details) - USD ($) $ in Thousands	Oct. 11, 2019	Jun. 30, 2019		May 31, 2019	May 30, 2019	Dec. 31, 2018		Oct. 12, 2016
Principal		$ 96,535				$ 80,691
Carrying amount		94,904				76,820	[1]
The 2017 Senior Credit Facility [Member]
Principal						27,000
Carrying amount						27,000
The 2019 Senior Credit Facility [Member]
Principal		84,400
Carrying amount		84,400
Convertible Second Lien Notes [Member]
Principal			[1]			53,691	[1]	$ 40,000
Carrying amount	$ 40,000		[1]			49,820	[1]	$ 29,000
New Convertible Second Lien Notes, New 2L Notes [Member]
Principal		12,135	[2]	$ 12,000			[2]
Carrying amount		$ 10,504	[2]	$ 10,600	$ 12,000		[2]

[1] The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019.

[2] The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2021. The principal included $0.1 million of accrued interest to be paid in-kind as of June 30, 2019. The carrying value included $1.4 million of unamortized debt discount as of June 30, 2019.

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Note 4 - Debt - Components of Debt, Interest Expense and Effective Interest Rate (Details) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018		Jun. 30, 2019	Jun. 30, 2018
Interest Expense		$ 3,398	$ 2,732		$ 7,055	$ 5,405
Effective Interest Rate
The 2017 Senior Credit Facility [Member]
Interest Expense		$ 364	$ 75		$ 872	$ 248
Effective Interest Rate		8.20%		[1]	7.20%	7.80%
The 2019 Senior Credit Facility [Member]
Interest Expense		$ 695			$ 695
Effective Interest Rate		5.90%			5.90%
Convertible Second Lien Notes [Member]
Interest Expense	[2]	$ 2,155	$ 2,657		$ 5,304	$ 5,157
Effective Interest Rate	[2]	23.90%	24.70%		24.10%	24.80%
New Convertible Second Lien Notes, New 2L Notes [Member]
Interest Expense	[3]	$ 184			$ 184
Effective Interest Rate		20.50%			20.50%

[1] Not meaningful due to the timing of borrowings during the three months ended June 30, 2018.

[2] The Convertible Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 23.9% and 24.1%, respectively, for the three and six months ended June 30, 2019 and 24.7% and 24.8%, respectively, for the three and six months ended June 30, 2018. Interest expense for the three months ended June 30, 2019 included $0.9 million of debt discount amortization and $1.2 million of paid in-kind interest, and interest expense for the three months ended June 30, 2018 included $1.0 million of debt discount amortization and $1.6 million of paid in-kind interest. Interest expense for the six months ended June 30, 2019 included $2.3 million of debt discount amortization and $3.0 million of paid in-kind interest, and interest expense for the six months ended June 30, 2018 included $1.8 million of debt discount amortization and $3.2 million of paid in-kind interest.

[3] The New 2L Notes have a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 20.5% for the three and six months ended June 30, 2019. Interest expense for the three and six months ended June 30, 2019 included less than $0.1 million of debt discount amortization and $0.1 million of accrued interest to be paid in-kind.

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Note 5 - Equity (Details Textual) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	May 31, 2019	May 29, 2019	Dec. 31, 2018
Common Stock, Par or Stated Value Per Share	$ 0.01		$ 0.01				$ 0.01
New Convertible Second Lien Notes, New 2L Notes [Member]
Debt Instrument, Convertible, Carrying Amount of Equity Component					$ 1.4	$ 1.4
Costless Warrants Associated with Convertible Second Lien Notes [Member]
Class of Warrant or Right, Exercised During Period	150,000	273,437	150,000	862,812
Warrants and Rights Outstanding, Term	10 years	10 years	10 years	10 years
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Stock Issued During Period, Shares, New Issues	150,000	273,437		315,937
Class of Warrant or Right, Outstanding	0	207,500	0	207,500

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Note 6 - Net Income (Loss) Per Common Share (Details Textual)	6 Months Ended
	Jun. 30, 2019
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Award of Initial Units Granted, Percent	0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Award of Initial Units Granted, Percent	250.00%

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Note 6 - Net Income (Loss) Per Common Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net income (loss) applicable to common stock		$ 11,779	$ (2,661)	$ 12,227	$ (7,985)
Weighted average shares of common stock outstanding - basic (in shares)		12,211	11,629	12,181	11,424
Net income (loss) per common share - basic (in dollars per share)		$ 0.96	$ (0.23)	$ 1	$ (0.70)
Interest, discount and amortization on New 2L Notes		$ 107		$ 107
Adjusted net income (loss) per common share		$ 11,886	$ (2,661)	$ 12,334	$ (7,985)
Common shares issuable upon conversion of the New 2L Notes (in shares)		569		569
Common shares issuable upon conversion of warrants of unsecured claim holders (in shares)		1,282		1,282
Common shares issuable on assumed conversion of restricted stock (4) (in shares)	[1]	519		466
Diluted weighted average shares of common stock outstanding (in shares)		14,581	11,629	14,498	11,424
Net income (loss) per common share - diluted (in dollars per share)	[2],[3],[4]	$ 0.82	$ (0.23)	$ 0.85	$ (0.70)
Share-based Payment Arrangement [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares)	[1]		491		346
Convertible Debt Securities [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares)			1,875		1,875
Warrant [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares)			1,642		1,642

[1] Common shares issuable on assumed conversion of share-based compensation assumes a payout of the Company's performance share awards at 100% of the initial units granted (or a ratio of one unit to one common share). The range of common stock shares which may be earned ranges from zero to 250% of the initial performance units granted.

[2] Common shares issuable on assumed conversion of share-based compensation for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. (4)

[3] Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.

[4] Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders for the periods in 2018 were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive.

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Note 7 - Income Taxes (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Income Tax Expense (Benefit), Total	$ 0	$ 0	$ 0	$ 0
Deferred Tax Assets, Valuation Allowance, Total					$ 84,100
Deferred Income Tax Assets, Net, Total					800
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax					$ 800
Unrecognized Tax Benefits, Ending Balance	$ 0		$ 0

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Note 8 - Commodity Derivative Activities (Details Textual) $ in Millions	Jun. 30, 2019 USD ($)
Commodity Contract [Member]
Loss Contingency, Estimate of Possible Loss	$ 12.1

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Note 8 - Commodity Derivative Activities - Summary of Gains and Losses on Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Gain (loss) on commodity derivatives not designated as hedges	$ 12,653	$ (2,174)	$ 11,645	$ (3,155)
Commodity Contract [Member]
Gain (loss) on commodity derivatives not designated as hedges, settled	1,973	(156)	213	(541)
Gain (loss) on commodity derivatives not designated as hedges, not settled	10,680	(2,018)	11,432	(2,614)
Gain (loss) on commodity derivatives not designated as hedges	$ 12,653	$ (2,174)	$ 11,645	$ (3,155)

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Note 8 - Commodity Derivative Activities - Outstanding Commodity (Details) - Not Designated as Hedging Instrument [Member] $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($) MMBTU bbl	Jun. 30, 2019 USD ($) MMBTU bbl
Natural Gas Swap with RBC Capital Markets [Member]
Weighted Average Fixed Price	2.677	2.677
Average Daily Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU	20,090
The 2019 Oil Swaps [Member]
Average Daily Volume, oil swaps (Barrel of Oil) | bbl		300
Total Volume, oil swaps (Barrel of Oil) | bbl		55,200
Weighted Average Fixed Price	51.08	51.08
Fair Value at Period End	$ (376)	$ (376)
Oil Swap With RBC Capital Markets [Member]
Average Daily Volume, oil swaps (Barrel of Oil) | bbl	217
Weighted Average Fixed Price	58.57	58.57
The 2020 Oil Swaps [Member]
Average Daily Volume, oil swaps (Barrel of Oil) | bbl		221
Total Volume, oil swaps (Barrel of Oil) | bbl		80,945
Weighted Average Fixed Price	59.02	59.02
Fair Value at Period End	$ 243	$ 243
The 2021 Oil Swaps [Member]
Average Daily Volume, oil swaps (Barrel of Oil) | bbl		200
Total Volume, oil swaps (Barrel of Oil) | bbl		18,000
Weighted Average Fixed Price	56.58	56.58
Fair Value at Period End	$ 37	$ 37
Total Crude Oil [Member]
Fair Value at Period End	$ (96)	$ (96)
The 2019 Natural Gas Swaps [Member]
Weighted Average Fixed Price	2.887	2.887
Fair Value at Period End	$ 9,587	$ 9,587
Average Daily Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		100,000
Total Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		18,400,000
The 2020 Natural Gas Swaps [Member]
Weighted Average Fixed Price	2.756	2.756
Fair Value at Period End	$ 2,155	$ 2,155
Average Daily Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		33,344
Total Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		12,204,000
The 2021 Natural Gas Swaps [Member]
Weighted Average Fixed Price	2.862	2.862
Fair Value at Period End	$ 118	$ 118
Average Daily Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		16,656
Total Volume, natural gas swaps (Millions of British Thermal Unit) | MMBTU		1,499,000
Total Natural Gas [Member]
Fair Value at Period End	11,860	$ 11,860
Crude Oil and Natural Gas Swaps [Member]
Fair Value at Period End	$ 11,764	$ 11,764

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Note 8 - Commodity Derivative Activities - Reconciliation of Gross Amounts to Amounts as Presented on Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Fair value of oil and natural gas derivatives - Current Assets	$ 11,421	$ 803
Fair value of oil and natural gas derivatives - Non-current Assets	719
Fair value of oil and natural gas derivatives - Current Liabilities	(376)
Fair value of oil and natural gas derivatives - Non-current Liabilities		$ (471)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Fair value of oil and natural gas derivatives - Current Assets	11,421
Fair value of oil and natural gas derivatives - Non-current Assets	719
Fair value of oil and natural gas derivatives - Current Liabilities	(376)
Fair value of oil and natural gas derivatives - Non-current Liabilities
Total	11,764
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value of oil and natural gas derivatives - Current Assets
Fair value of oil and natural gas derivatives - Non-current Assets
Fair value of oil and natural gas derivatives - Current Liabilities
Fair value of oil and natural gas derivatives - Non-current Liabilities
Total
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value of oil and natural gas derivatives - Current Assets	11,421
Fair value of oil and natural gas derivatives - Non-current Assets	719
Fair value of oil and natural gas derivatives - Current Liabilities	(376)
Fair value of oil and natural gas derivatives - Non-current Liabilities
Total	11,764
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value of oil and natural gas derivatives - Current Assets
Fair value of oil and natural gas derivatives - Non-current Assets
Fair value of oil and natural gas derivatives - Current Liabilities
Fair value of oil and natural gas derivatives - Non-current Liabilities
Total

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Note 8 - Commodity Derivative Activities - Derivative Table, Fair Value with Netting (Details) - Not Designated as Hedging Instrument [Member] - Commodity Contract [Member] - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivative Asset, Gross Amount	$ 11,764	$ 332
Derivative Asset, Amount Offset
Derivative Asset, As Presented	11,764	332
Current Assets [Member]
Derivative Asset, Gross Amount	11,421	2,893
Derivative Asset, Amount Offset		(2,090)
Derivative Asset, As Presented	11,421	803
Non-current Assets [Member]
Derivative Asset, Gross Amount	719
Derivative Asset, Amount Offset
Derivative Asset, As Presented	719
Current Liabilities [Member]
Derivative Asset, Gross Amount	(376)	(2,090)
Derivative Asset, Amount Offset		2,090
Derivative Asset, As Presented	(376)
Non-current Liabilities [Member]
Derivative Asset, Gross Amount		(471)
Derivative Asset, Amount Offset
Derivative Asset, As Presented		$ (471)

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Note 10 - Leases (Details Textual) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Operating Lease, Weighted Average Remaining Lease Term	1 year 292 days	1 year 292 days
Operating Lease, Weighted Average Discount Rate, Percent	8.00%	8.00%
Operating Lease, Payments	$ 0.4	$ 0.8

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Note 10 - Leases - Lease Cost and Information (Details) - USD ($) $ in Thousands		3 Months Ended	6 Months Ended
		Jun. 30, 2019	Jun. 30, 2019
Cash paid for operating lease liabilities		$ 451	$ 851
General and Administrative Expense [Member]
Building lease cost		403	756
Variable lease cost (1)	[1]	$ 48	$ 95

[1] Includes building operating expenses.

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Note 10 - Leases - Assets and Liabilities (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Accumulated depreciation	$ 626
Lease asset, net	2,296
Total lease liabilities	2,882
Furniture, Fixtures and Equipment and Other Capital Assets [Member]
Lease asset, gross	2,922
Accounts Payable and Accrued Liabilities [Member]
Current lease liability	1,359
Other Noncurrent Liabilities [Member]
Non-current lease liability	$ 1,523

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Note 10 - Leases - Lease Liability Maturities (Details) $ in Thousands	Jun. 30, 2019 USD ($)
2019	$ 770
2020	1,540
2021	813
2022
2023
Thereafter
Total lease payments	3,123
Less imputed interest	241
Present value of lease liabilities	$ 2,882

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Note 10 - Leases - Minimum Noncancelable Operating Lease Obligations (Details) $ in Thousands	Dec. 31, 2018 USD ($)
2019	$ 3,753
2020	1,556
2021	513
2022
2023
Thereafter
Future minimum lease obligations	$ 5,822

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Note 11 - Dispositions (Details Textual) - USD ($) $ in Thousands				3 Months Ended	6 Months Ended
	Mar. 01, 2019	May 21, 2018	Feb. 28, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Proceeds from Sale of Productive Assets, Total	$ 1,300	$ 3,300	$ 23,000		$ 1,284	$ 26,920
Other Miscellaneous Acreage [Member]
Proceeds from Sale of Productive Assets, Total				$ 400		$ 700