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 March 31, 2017

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

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	☒
(Do not check if a 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 7(a)(2)(B) of the Securities 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 9,108,826 shares of common stock outstanding on May 9, 2017.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

TABLE OF CONTENTS

		Page
PART I	FINANCIAL INFORMATION	3
ITEM 1	FINANCIAL STATEMENTS	3
	Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	3
	Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016	5
	Notes to Consolidated Financial Statements	6
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 4	CONTROLS AND PROCEDURES	25
PART II	OTHER INFORMATION	25
ITEM 1	LEGAL PROCEEDINGS	25
ITEM 1A	RISK FACTORS	25
ITEM 6	EXHIBITS	26

2

PART I – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

	March 31, 2017			December 31, 2016
ASSETS	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	37,949		$	36,850
Accounts receivable, trade and other, net of allowance	260			1,998
Accrued oil and natural gas revenue	3,841			3,142
Inventory	4,008			4,125
Prepaid expenses and other	374			755
Total current assets	46,432			46,870
PROPERTY AND EQUIPMENT:
Unevaluated properties	13,367			24,206
Oil and natural gas properties (full cost method)	78,047			60,936
Furniture, fixtures and equipment	986			984
	92,400			86,126
Less: Accumulated depletion, depreciation and amortization	(6,245		)	(4,006		)
Net property and equipment	86,155			82,120
Other	723			322
TOTAL ASSETS	$	133,310		$	129,312
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	16,256		$	14,392
Accrued liabilities	8,094			3,882
Fair value of commodity derivatives	804			—
Total current liabilities	25,154			18,274
Long term debt, net	49,132			47,205
Accrued abandonment cost	3,023			2,933
Total liabilities	77,309			68,412
Commitments and contingencies (See Note 7)
STOCKHOLDERS’ EQUITY:
Common stock: $0.01 par value, 75,000,000 shares authorized, and 9,108,826 shares issued and outstanding	91			91
Additional paid in capital	65,942			65,116
Accumulated deficit	(10,032		)	(4,307		)
Total stockholders’ equity	56,001			60,900
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	133,310		$	129,312

See accompanying notes to consolidated financial statements.

3

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
	2017			2016
REVENUES:
Oil and natural gas revenues	$	9,411		$	6,464
Other	2			(219		)
	9,413			6,245
OPERATING EXPENSES:
Lease operating expense	4,311			2,336
Production and other taxes	659			739
Transportation and processing	1,176			431
Depreciation, depletion and amortization	2,294			3,145
Exploration	—			197
General and administrative	4,463			6,364
Gain on sale of assets	—			(837		)
	12,903			12,375
Operating loss	(3,490		)	(6,130		)
OTHER INCOME (EXPENSE):
Interest expense	(2,179		)	(8,313		)
Interest income and other	9			—
(Loss)/gain on derivatives not designated as hedges	(260		)	24
	(2,430		)	(8,289		)
Restructuring	—			(4,314		)
Reorganization items, net	195			—
Loss before income taxes	(5,725		)	(18,733		)
Income tax benefit	—			—
Net loss	(5,725		)	(18,733		)
Preferred stock, net	—			1,004
Net loss applicable to common stock	$	(5,725	)	$	(19,737	)
PER COMMON SHARE
Net loss applicable to common stock - basic	$	(0.63	)	$	(0.26	)
Net loss applicable to common stock - diluted	$	(0.63	)	$	(0.26	)
Weighted average common shares outstanding - basic	9,109			74,521
Weighted average common shares outstanding - diluted	9,109			74,521

See accompanying notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(5,725	)	$	(18,733	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	2,294			3,145
Loss/(gain) on commodity derivatives not designated as hedges	260			(24		)
Net cash received in settlement of commodity derivative instruments	142			—
Amortization of leasehold costs	—			24
Share based compensation (non-cash)	1,008			1,070
Bonus share based compensation (non-cash)	720			—
Gain on sale of assets	—			(837		)
Embedded derivative	—			(3,845		)
Amortization of finance cost, debt discount, paid in-kind interest and accretion	1,927			4,329
Materials inventory write-down	—			156
Reorganization items, net	(181		)	—
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance	1,738			892
Accrued oil and natural gas revenue	(699		)	419
Inventory	—			(512		)
Prepaid expenses and other	88			735
Accounts payable	1,864			(3,867		)
Accrued liabilities	1,229			6,560
Net cash provided by (used in) operating activities	4,665			(10,488		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(3,384		)	(1,006		)
Proceeds from sale of assets	—			289
Net cash used in investing activities	(3,384		)	(717		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings	—			13,000
Payments related to Convertible Second Lien Notes	(36		)	—
Note conversions	—			(804		)
Registration costs	(146		)	(88		)
Other	—			(5		)
Net cash (used in) provided by financing activities	(182		)	12,103
INCREASE IN CASH AND CASH EQUIVALENTS	1,099			898
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	36,850			11,782
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	37,949		$	12,680
Supplemental disclosures of cash flow information:
Cash paid for Interest	$	309		$	451

See accompanying notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (together with its 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 (the “SEC”) 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, 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year or for any interim period. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period.

Fresh Start Accounting—We applied fresh start accounting upon emergence from bankruptcy on October 12, 2016 (the "Effective Date"). This resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. As a result, our consolidated statement of operations subsequent to the Effective Date are not comparable to our consolidated statement of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented in a format that illustrates the lack of comparability between amounts presented on or after October 12, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

All references made to "Successor" or "Successor Company" relate to the Company on and subsequent to the Effective Date. References to the “Successor" in this quarterly report relate to the periods after October 12, 2016 which includes the first quarter of 2017. References to "Predecessor" or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date which includes the first quarter of 2016.

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.

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 March 31, 2017 and December 31, 2016:

(In thousands)	March 31, 2017		December 31, 2016
Trade payables	$	4,522	$	2,004
Revenue payable	11,101		11,296
Prepayments from partners	496		965
Miscellaneous payables	137		127
Total accounts payable	$	16,256	$	14,392

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.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Upon emergence from bankruptcy, we elected to adopt the Full Cost Method.

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. 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.

We amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. This entails the quarterly provision for DD&A expense being computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and natural gas properties and future development costs.

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 quarter ended March 31, 2017.

Impairment—Prior to October 12, 2016 under the Successful Efforts Method of Accounting, we periodically assessed our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they were not overstated or carried in excess of fair value, which was computed using Level 3 inputs such as discounted cash flow models or valuations. Significant Level 3 assumptions associated with discounted cash flow models or valuations used in the impairment evaluation included estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation was performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicated that our oil and natural gas properties may be impaired.

To determine if a field was impaired, we compared the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves were taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. For each property determined to be impaired, we recognized an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.

Fair value was estimated to be the present value of expected future net cash flows. Any impairment charge incurred was recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this

calculation was subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash

flows and fair value.

We had no impairment for the quarter ended March 31, 2016.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO 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 nonperformance, 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 which are derived principally from or corroborated by observable market data. Included in this Level are our Exit Credit Facility 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 counterparties; 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 acquisitions and impairments of oil and natural gas properties, if any, and our asset retirement obligations.

As of March 31, 2017 and December 31, 2016, 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.

Depreciation and Depletion—Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.

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.

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 2.

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 measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Revenue Recognition—Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. 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. AtMarch 31, 2017and December 31, 2016, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

interest rates. 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 counterparty 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 6.

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 bases 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 5.

Net Income or Net Loss Per Share—Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted average number of common shares 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 4.

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 7.

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. The fair value of each restricted stock award is measured using the closing price of our common stock on the day of the award.

New Accounting Pronouncements

On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the amendments are effective for annual periods beginning after December 15, 2016. We adopted this standard in 2017 and anticipate no material impact on our consolidated financial statements until the fourth quarter of 2017, when the initial vestings of restricted stock issued under our Management Incentive Plan occur.

On February 25, 2016 the FASB issued ASU 2016-02, Leases (Topic 842). The key difference between the existing standards and ASU 2016-02 is the requirement for lessees to recognize on their balance sheet all lease contracts with lease terms greater than 12 months, including operating leases. Specifically, lessees are required to recognize on the balance sheet at lease commencement, both (i) a right-of-use asset, representing the lessee’s right to use the leased asset over the term of the lease, and (ii) a lease liability, representing the lessee’s contractual obligation to make lease payments over the term of the lease. For lessees, ASU 2016-02 requires classification of leases as either operating or finance leases, which are similar to the current operating and capital lease classifications. However, the distinction between these two classifications under the ASU does not relate to balance sheet treatment, but relates to treatment and recognition in the statements of income and cash flows. Lessor accounting is largely unchanged from current US GAAP. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, for public entities. Early application is permitted. We

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

NOTE 2—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2017 is as follows (in thousands):

	March 31, 2017
Beginning balance at December 31, 2016	$	2,933
Liabilities incurred	35
Accretion expense	55
Ending balance at March 31, 2017	$	3,023
Current liability	$	—
Long term liability	$	3,023

NOTE 3—Debt

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

	March 31, 2017				December 31, 2016
	Principal		Carrying Amount		Principal		Carrying Amount
Exit Credit Facility	$	16,651	$	16,651	$	16,651	$	16,651
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	42,559		32,481		41,170		30,554
Total debt	$	59,210	$	49,132	$	57,821	$	47,205

⁽¹⁾ The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes $2.6 million and $1.2 million of paid in-kind interest at March 31, 2017 and December 31, 2016, respectively. The carrying value includes $10.1 million and $10.6 million of unamortized debt discount at March 31, 2017 and December 31, 2016, respectively.

The following table summarizes the total interest expense for the periods shown including contractual interest expense, amortization of debt discount, accretion and financing costs and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates).

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Successor				Predecessor
	March 31, 2017				March 31, 2016
	Interest Expense		Effective Interest Rate		Interest Expense		Effective Interest Rate
Successor Exit Credit Facility	$	252	6.1	%	$	—	—	%
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	1,927		24.2	%	—		—	%
Predecessor Senior Credit Facility	—		—	%	870		7.2	%
8.0% Second Lien Senior Secured Notes due 2018 **	—		—	%	1,109		18.7	%
8.875% Senior Notes due 2019	—		—	%	2,688		9.1	%
3.25% Convertible Senior Notes due 2026	—		—	%	3		3.3	%
5.0% Convertible Senior Notes due 2029	—		—	%	84		5.0	%
5.0% Convertible Senior Notes due 2032	—		—	%	2,053		8.4	%
5.0% Convertible Exchange Senior Notes due 2032	—		—	%	1,484		*
Other	—		—	%	22		*
Total debt	$	2,179			$	8,313

(1) Interest expense for the period ended Mach 31, 2017 includes $0.5 million of debt discount amortization and $1.4 million of paid in-kind interest.

* - Not meaningful.

** - Includes $3.8 million gain from the change in fair value of the embedded derivative associated with the 8.0% Second Lien Notes.

Exit Credit Facility

On October 12, 2016, upon consummation of the plan of reorganization, the Company entered into an Exit Credit Agreement (the “Exit Credit Agreement”) with the Subsidiary, as borrower (the “Borrower”), and Wells Fargo Bank, National Association, as administrative agent (“the Administrative Agent”), and certain other lenders party thereto. Pursuant to the Exit Credit Agreement, the lenders party thereto agreed to provide the Borrower with a $20.0 million senior secured term loan credit facility (the “Exit Credit Facility”), with available borrowing capacity of $20.0 million. As of March 31, 2017, we had $16.7 million outstanding on the Exit Credit Facility.

The maturity date of the Exit Credit Agreement is September 30, 2018, unless the Borrower notifies the Administrative Agent that it intends to extend the maturity date to September 30, 2019, subject to certain conditions and the payment of a fee.

Until such maturity date, the Loans (as defined in the Exit Credit Agreement) under the Exit Credit Agreement shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 4.50% or (ii) adjusted LIBOR plus an applicable margin of 5.50%. As of March 31, 2017, the interest rate on the Exit Credit Facility was 6.53%.

The Borrower may elect, at its option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement).

The Borrower may be required to make mandatory prepayments of the Loans under the Exit Credit Agreement if the total borrowings exceed the aggregate credit amounts, and if the Borrower is not in compliance with the Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) or the Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement).

Additionally, if the Borrower has outstanding borrowings and the Consolidated Cash Balance (as defined in the Exit Credit Agreement and the First Amendment and Consent to Exit Credit Agreement dated December 22, 2016) exceeds (i) the sum of $27.5 million plus $21.3 million, which is calculated as the Equity Issuance Net Proceeds from the December 19, 2016 private placement less $2.5 million, as of the close of business on the most recently ended business day on or before March 31,

11

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2018 or (ii) $7.5 million as of the close of business on the most recently ended business day on or after April 1, 2018, the Borrower may also be required to make mandatory prepayments in an aggregate principal amount equal to such excess.

Furthermore, the Borrower is required to make certain mandatory prepayments within one business day of (i) the issuance of any Equity Interests (as defined in the Exit Credit Agreement) of the Company, (ii) the consummation of any sale or other disposition of Property (as defined in the Exit Credit Agreement) and (iii) the assignment, termination or unwinding of any Swap Agreements (as defined in the Exit Credit Agreement).

Amounts outstanding under the Exit Credit Agreement are guaranteed by the Company and secured by a security interest in substantially all of the assets of the Company and the Borrower.

The Exit Credit Agreement contains certain customary representations and warranties, including as to organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; subsidiaries; location of business and offices; properties; titles, etc.; maintenance of properties; gas imbalances, prepayments; marketing of production; swap agreements; use of loans; solvency; sanctions laws and regulations; foreign corrupt practices; money laundering laws; and embargoed persons.

The Exit Credit Agreement also contains certain affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments; and swap agreements.

The Exit Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.5 to 1.0 initially, and increasing to 2.0 to 1.0 or after December 31, 2018, (ii)  Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.10 to 1.00 initially, and increasing to 1.35 to 1.00 and 1.50 to 1.00 after March 31, 2017 and September 30, 2017, respectively, in the case of clauses (i) and (ii), to be determined as of January 1 and July 1 each year and as of the date of any Material Acquisition (as defined in the Exit Credit Agreement) or Material Disposition (as defined in the Exit Credit Agreement), (iii) commencing with the fiscal quarter ending March 31, 2018, a ratio of Debt (as defined in the Exit Credit Agreement) as of the end of each fiscal quarter to EBITDAX for the twelve months ending on the last day of such fiscal quarter, not to exceed 4.00 to 1.00, (iv) limitations on Consolidated Cash Balance, (v) limitations on general and administrative expenses and (vi) minimum liquidity requirements.

The Exit Credit Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; voluntary and involuntary bankruptcy; judgments; and change of control.

As of March 31, 2017, we were in compliance with all covenants within the Exit Credit Agreement.

13.50% Convertible Second Lien Senior Secured Notes Due 2019

On October 12, 2016, the Company and the Subsidiary, entered into a purchase agreement (the “Purchase Agreement”) with each entity identified as a Shenkman Purchaser on Appendix A to the Purchase Agreement (collectively, the “Shenkman Purchasers”), CVC Capital Partners (acting through such of its affiliates to managed funds as it deems appropriate), J.P. Morgan Securities LLC (acting through such of its affiliates or managed funds as it deems appropriate), Franklin Advisers, Inc. (as investment manager on behalf of certain funds and accounts), O’Connor Global Multi-Strategy Alpha Master Limited and Nineteen 77 Global Multi-Strategy Alpha (Levered) Master Limited (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 is convertible at the option of the Purchasers at any time prior to the scheduled maturity date into an amount of the Company’s common stock equal to 15% of the common stock of the reorganized Company on a fully diluted basis, subject to adjustments. At closing, the Purchasers were issued 10-year costless warrants for common stock equal to 20% of the New Common Stock of the reorganized Company on a fully diluted basis. Holders of the Convertible Second Lien Notes have a second priority lien on all assets of the Debtors, and have a continuing right to appoint two members to the Board as long as the Convertible Second Lien Notes are outstanding.

12

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Convertible Second Lien Notes will mature on August 30, 2019, or such later date as set forth in the Convertible Second Lien Notes, but in no event later than March 30, 2020. The Convertible Second Lien 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 Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional Second Lien Notes (“PIK Interest Notes”). The PIK Interest Notes are not convertible. During such time as the Exit Credit Agreement (but not any refinancing or replacement thereof) is in effect, interest on the Convertible Second Lien Notes must be paid in-kind.

The Indenture governing the Convertible Second Lien Notes 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 sale of assets and stock; business activities; transactions with affiliates; and changes of control.

The Indenture also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.10 to 1.00 on or before March 31, 2017 initially and increasing to 1.35 to 1.00 after March 31, 2017 but on or before September 30, 2017 and 1.50 to 1.00 after September 30, 2017, to be determined as of January 1 and July 1 of each year; (ii) limitations on general and administrative expenses and (iii)

minimum liquidity requirements.

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 is amortized using the effective interest rate method based upon an original term through August 30, 2019. $10.1 million of debt discount remains to be amortized on the Convertible Second Lien Notes as of March 31, 2017.

As of March 31, 2017, we were in compliance with all covenants within the Indenture that governs the Convertible Second Lien Notes.

NOTE 4—Net Loss Per Common Share

Upon our emergence from bankruptcy on October 12, 2016, as discussed in Note 1, the Predecessor Company's outstanding common stock and preferred stock were canceled, and new common stock and warrants were then issued.

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three months ended March 31, 2017 and 2016. The following table sets forth information related to the computations of basic and diluted loss per share.

13

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
	2017			2016
	(Amounts in thousands, except per share data)
Basic and Diluted loss per share:
Net loss applicable to common stock	$	(5,725	)	$	(19,737	)
Weighted average shares of common stock outstanding	9,109			74,521
Basic and Diluted loss per share (1) (2) (3) (4)	$	(0.63	)	$	(0.26	)
(1) Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid were not presented as they would have been anti-dilutive.	—			16,878
(2) Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Exchange Notes and 2032 Notes or interest paid were not presented as they would have been anti-dilutive.	—			5,910
(3) Common shares issuable on assumed conversion of restricted stock were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	288			13,949
(4) Common shares issuable on the 13.50% Convertible Second Lien Senior Secured Notes due 2019, associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	5,664			—

NOTE 5—Income Taxes

We recorded no income tax expense or benefit for the three months ended March 31, 2017. We recorded a valuation allowance at December 31, 2016 which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, our deferred tax assets were unrecoverable. 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 March 31, 2017.

As of March 31, 2017, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2016.

NOTE 6—Commodity Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. 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 months ended March 31, 2017 and 2016:

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
Oil and Natural Gas Derivatives (in thousands)	2017			2016
Gain on commodity derivatives not designated as hedges, settled	$	142		$	—
Gain (loss) on commodity derivatives not designated as hedges, not settled	(402		)	24
Total gain (loss) on commodity derivatives not designated as hedges	$	(260	)	$	24

14

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 the 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 counterparties. Neither our counterparties nor we require any collateral upon entering derivative contracts. We were not at risk of losing any fair value amounts had our counterparties been unable to fulfill their obligations as of March 31, 2017 and December 31, 2016 because we did not have a net derivative asset on our Consolidated Balance Sheets at those periods.

As of March 31, 2017, the open positions on our outstanding commodity derivative contracts, all of which were natural gas contracts with BP, were as follows:

Contract Type	Daily Volume (MMBtu)	Total Volume (MMBtu)	Fixed Price		Fair Value at March 31, 2017 (In thousands)
Natural Gas Swaps
2017	6,000	1,470,000	$	3.20	$	(182	)
2018	12,000	4,380,000	$3.00 - $3.015		$	(79	)
Natural Gas Costless Collars
2017	12,000	3,300,000	$3.00 - $3.60		$	(141	)

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of March 31, 2017 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.

Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	—		$	—	$	—
Non-current Assets Commodity Derivatives	—		402			—		402
Current Liabilities Commodity Derivatives	—		(804		)	—		(804		)
Non-current Liabilities Commodity Derivatives	—		—			—		—
Total	$	—	$	(402	)	$	—	$	(402	)

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 for the periods ending March 31, 2017 and December 31, 2016:

	March 31, 2017									December 31, 2016
Fair Value of Oil and Natural Gas Derivatives (in thousands)	Gross Amount			Amount Offset			As Presented			Gross Amount		Amount Offset		As Presented
Current Assets Commodity Derivatives	$	336		$	(336	)	$	—		$	—	$	—	$	—
Fair Value of Commodity Derivatives - Other Non-current Assets	413			(11		)	402			—		—		—
Fair Value of Commodity Derivatives - Current Liability	(1,140		)	336			(804		)	—		—		—
Non-current Liabilities Commodity Derivatives	(11		)	11			—			—		—		—
Total	$	(402	)	$	—		$	(402	)	$	—	$	—	$	—

15

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7—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, will not be material to our consolidated financial position results of operations or liquidity.

Operating Leases—We have commitments under an operating lease agreement for office space and office equipment. Total rent expense for the three months ended March 31, 2017 and March 31, 2016 was approximately $0.4 million and $0.4 million, respectively.

Defined Contribution Plan – We have a defined contribution plan (“DCP”) which has a Company matching option to employees' contributions. Participation in the DCP is voluntary and all employees of the Company are eligible to participate. We suspended the Company's match in April 2016. We charged to expense plan contributions of zero and $0.1 million for the three months ended March 31, 2017 and March 31, 2016, respectively.

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;

16

• 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 laws, and local environmental laws and regulations;

• the impact of restrictive covenants in our debt agreements;

• the creditworthiness of our financial counterparties and operation partners;

• failure to satisfy our short- or long-term liquidity needs, including our inability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; 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, 2016.

Overview

We are an independent oil and natural gas company engaged in the exploration, development and production of 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 have historically employed commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.

Emergence from Bankruptcy

    On April 15, 2016, we and our subsidiary Goodrich Petroleum Company, L.L.C. filed voluntary Bankruptcy petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the

17

Southern District of Texas, Houston Division, to pursue a Chapter 11 plan of reorganization. We filed a motion with the Bankruptcy Court seeking joint administration of the Chapter 11 Cases under the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). Our joint plan of reorganization (the “Plan of Reorganization”) was confirmed by the Bankruptcy Court on September 28, 2016 and we emerged from bankruptcy on October 12, 2016 (the “Effective Date”).

Upon our emergence from bankruptcy, we adopted Fresh Start Accounting in accordance with the requirements of FASB ASC 852, "Reorganizations". This resulted in our becoming a new entity for financial reporting purposes. At that time, our assets and liabilities were recorded at their fair values as of the Effective Date. The effects of the Plan of Reorganization and our application of fresh start accounting are reflected in our consolidated financial statements as of December 31, 2016. The related adjustments were recorded in our consolidated statement of operations as reorganization items for the year to date period ending on the Effective Date.

The application of fresh start accounting and the effects of the implementation of our Plan of Reorganization resulted in our Consolidated Financial Statements on or after October 12, 2016 not being comparable with the Consolidated Financial Statements prior to that date. Our financial results for periods following our application of fresh start accounting will be different from historical trends, and the differences may be material.

All references made to “Successor” or “Successor Company” relate to the Company on and subsequent to the Effective Date. References to the “Successor” in this quarterly report relate to the periods after October 12, 2016 which includes the first quarter of 2017. References to “Predecessor” or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date which includes the first quarter of 2016.

On the Effective Date, to better reflect the true economics of our exploration and development of oil and natural gas reserves, we transitioned from the Successful Efforts Method of Accounting for Oil and Gas Activities to the Full Cost Method.

Primary Operating Areas

Haynesville Shale Trend

Our development acreage in this trend is primarily centered in DeSoto and Caddo parishes, Louisiana and Angelina and Nacogdoches counties, Texas. We held approximately 48,000 gross (23,000 net) acres as of March 31, 2017 producing from and prospective for the Haynesville Shale Trend. Our net production volumes from our Haynesville Shale Trend wells represented approximately 79% of our total equivalent production on a Mcfe basis for the first quarter of 2017. We began drilling two gross (1.4 net) wells in the first quarter 2017. We plan to focus all our 2017 drilling efforts in the Haynesville Shale Trend.

Tuscaloosa Marine Shale Trend

We held approximately 176,000 gross (128,000 net) acres in the TMS as of March 31, 2017. We have 2 gross (1.7 net) TMS wells drilled and waiting on completion. Our net production volumes from our TMS wells represented approximately 21% of our total equivalent production on a Mcfe basis and approximately 100% of our total oil production for the first quarter of 2017. We did not conduct any capital workover operations on any wells during the first quarter of 2017.

Eagle Ford Shale Trend

We hold approximately 14,000 net acres of undeveloped leasehold, in the Eagle Ford Shale Trend all of which is prospective for future development or sale.

Results of Operations

In addition to adopting Fresh Start Accounting, the Successor also adopted the Full Cost Method of Accounting as of October 12, 2016. Prior to October 12, 2016, the Predecessor used the Successful Efforts Method of Accounting. The results of operations of the Successor and the Predecessor are not generally comparable nor are they individually comparable with prior periods. We believe however, that production volumes, oil and natural gas revenues, lease operating expenses and production and other taxes are generally comparable and consequently, unless otherwise indicated, the tables and discussions below include such comparisons between the Predecessor and the Successor for these operational items. We believe this presentation gives the reader a better understanding of our operational results in 2017.

The Predecessor 2016 Period results of operations reflects the period from January 1, 2016 to March 31, 2016. The items that had the most material financial effect on the Net Loss of $18.7 million for the three months ended March 31, 2016

18

were the cost of our failed restructuring effort prior to filing for bankruptcy, interest expense and depletion, depreciation and amortization expense.

The Successor 2017 Period results of operations reflects the period from January 1, 2017 to March 31, 2017. The item that had the most material financial effect on the Net Loss of $5.7 million for the three months ended March 31, 2017 was lease operating expense. Lease operating expense in the period included $2.1 million in workover expenses incurred in our effort to increase production volumes after having curtailed such expenditures while in bankruptcy.

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.

	Three Months Ended March 31,
	Successor		Predecessor
(In thousands, except for price data)	2017		2016		Variance
Revenues:
Natural gas	$	5,301	$	1,567	$	3,734		238	%
Oil and condensate	4,110		4,897		(787		)	(16	)%
Natural gas, oil and condensate	9,411		6,464		2,947			46	%
Net Production:
Natural gas (MMcf)	1,833		1,571		262			17	%
Oil and condensate (MBbls)	82		154		(72		)	(47	)%
Total (Mmcfe)	2,324		2,494		(170		)	(7	)%
Average daily production (Mcfe/d)	25,822		27,403		(1,581		)	(6	)%
Average realized sales price per unit:
Natural gas (per Mcf)	$	2.89	$	1.00	$	1.89		189	%
Natural gas (per Mcf) including cash settled derivatives	$	2.97	$	1.00	$	1.97		197	%
Oil and condensate (per Bbl)	$	50.12	$	31.84	$	18.28		57	%
Average realized price (per Mcfe)	$	4.05	$	2.59	$	1.46		56	%

Revenues from Operations

Natural gas, oil and condensate revenues increased by $2.9 million for the three months ended March 31, 2017 compared to the same period in 2016, primarily driven by higher natural gas production and higher realized oil and natural gas prices. The increase in natural gas production volumes is attributed to two Haynesville Shale Trend wells drilled in late 2016. Beginning in August 2016, we elected to take our production in-kind and market the majority of our non-operated Haynesville Shale Trend natural gas volumes resulting in an improvement in the prices we received on such natural gas volumes. Natural gas realized prices for the three months ended March 31, 2016 included the netting of transportation and processing costs on such volumes which was discontinued upon taking our production in-kind. For the three months ended March 31, 2017, 56% of our oil and natural gas revenue was attributable to natural gas sales compared to 24% for the three months ended March 31, 2016. We are concentrating on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend.

Operating Expenses

As described below, operating expenses increased $2.4 million to $6.1 million in the three months ended March 31, 2017 compared to the same period in 2016. The increase in operating expenses was primarily the result of $2.1 million of lease operating expense workover costs and recognition of additional transportation expense in the first quarter of 2017 by virtue of taking our production in-kind and selling our non-operated natural gas production in the Haynesville Shale Trend.

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	Three Months Ended March 31,
	Successor		Predecessor
Operating Expenses (in thousands)	2017		2016		Variance
Lease operating expenses	$	4,311	$	2,336	$	1,975		85	%
Production and other taxes	659		739		(80		)	(11	)%
Transportation and processing	1,176		431		*			*
Exploration	—		197		*			*
Operating Expenses per Mcfe
Lease operating expenses	$	1.86	$	0.94	$	0.92		98	%
Production and other taxes	0.28		0.30		(0.02		)	(7	)%
Transportation and processing	0.51		0.17		*			*
Exploration	—		0.08		*			*

* Not Comparable

Lease Operating Expense

Lease operating expense increased during the three months ended March 31, 2017 compared to the three months ended March 31, 2016. The increase is substantially attributed to an increase in workover expense. We incurred $2.1 million in workover cost in the three months ended March 31, 2017 and $0.2 million of workover cost in the same period in 2016.

Production and Other Taxes

Production and other taxes for the three months ended March 31, 2017 included production tax of $0.3 million and ad valorem tax of $0.3 million. During the comparable period in 2016, production and other taxes included production tax of $0.3 million and ad valorem tax of $0.4 million.

Production taxes remained flat reflecting decreased oil production volumes directly offset by tax increases due to the expiration of the exemption on certain wells in Mississippi and Louisiana. The State of Mississippi has enacted an exemption from the existing 6.0% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which is partially offset by a 1.3% local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months from the date of first sale of production or (ii) payout of the well. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax 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. The net revenues from our wells drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions.

The slight decrease in ad valorem tax between periods reflects the reduction in the assessed values of our properties.

Transportation and Processing Expense

Transportation and processing expense for the three months ended March 31, 2017 includes $1.0 million of transportation fees incurred on natural gas volumes that we take in-kind and pay directly to the transporter on non-operated Haynesville Shale Trend natural gas volumes, effective with August 2016 production. The transportation and processing expense for the three months ended March 31, 2016 did not include these take in-kind transportation fees as gathering fees for that period were netted against the Company's realized natural gas price.

Exploration

The Successor Company adopted the Full Cost Method of accounting as of October 12, 2016, resulting in Exploration Cost being capitalized to the full cost pool rather than expensed.

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	Three Months Ended March 31,
	Successor		Predecessor
Operating Expenses (in thousands)	2017		2016		Variance
Depreciation, depletion and amortization	$	2,294	$	3,145	*	*
General and administrative	4,463		6,364		*	*
Operating Expenses per Mcfe
Depreciation, depletion and amortization	$	0.99	$	1.26	*	*
General and administrative	1.92		2.55		*	*

* Not Comparable

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

DD&A expense in the 2017 Successor Period is calculated on the Full Cost Method of Accounting adopted upon our emergence from bankruptcy based upon asset carrying values as of December 31, 2016.

DD&A expense in the 2016 Predecessor Period is calculated on the Successful Efforts Method of Accounting.

General and Administrative (“G&A”) Expense

The Successor Company recorded $4.5 million in G&A expense in the three months ended March 31, 2017, which includes non-cash expenses of (i) $1.0 million for share based compensation, (ii) $0.7 million in performance bonuses to be compensated in common stock and (iii) $0.2 million of office rent amortization.

The Predecessor Company recorded $6.4 million in G&A expense in the three months ended March 31, 2016, which includes $1.1 million of share based compensation.

Other Income (Expense)

	Three Months Ended March 31,
Other income (expense) (in thousands):	Successor			Predecessor
	2017			2016
Interest expense	$	(2,179	)	$	(8,313	)
Gain (loss) on commodity derivatives not designated as hedges	(260		)	24
Average funded borrowings adjusted for debt discount and accretion	$	49,132		$	431,901
Average funded borrowings	$	59,210		$	434,196

Interest Expense

The Successor Company's interest expense for the three months ended March 31, 2017 reflects cash interest of $0.3 million incurred on the Exit Credit Facility and non-cash interest of $1.9 million incurred on the Convertible Second Lien Notes, which includes the paid in-kind interest and amortization of debt discount.

The Predecessor Company's interest expense for the three months ended March 31, 2016 reflects interest payable in cash of $5.2 million and non-cash interest of $3.1 million. The interest expense recorded as of March 31, 2016 was never paid as the underlying debt was canceled in bankruptcy.

Gain (loss) on Commodity Derivatives Not Designated as Hedges

Loss on commodity derivatives not designated as hedges for the three months ended March 31, 2017 is comprised of an unrealized loss of $0.4 million, representing the change of the fair value of our natural gas derivative contracts off set by $0.1 million gain on cash settlement.

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Restructuring

As a result of the our efforts to restructure the Company outside of bankruptcy and the preliminary preparation involved in filing the Chapter 11 Cases during the first quarter of 2016, we incurred significant professional fees and other costs. Restructuring costs during the first quarter of 2016 totaled $4.3 million. No restructuring costs were incurred during the first quarter of 2017.

Reorganization items, net

 We anticipate that we will continue to incur professional fees and costs until obtaining a final decree from the bankruptcy court. We believe that the estimated liability we have established for these costs is sufficient to cover such cost.

Income Tax Benefit

We recorded no income tax expense or benefit for the three months ended March 31, 2017. We recorded a valuation allowance at December 31, 2016 which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, our deferred tax assets were unrecoverable. 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 March 31, 2017.

Adjusted EBITDA/EBITDAX

Adjusted EBITDA/EBITDAX 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. We define Adjusted EBITDAX as earnings before interest expense, income tax, DD&A, exploration expense, share based compensation expense and impairment of oil and natural gas properties. We calculate Adjusted EBITDA in the same way, but EBITDA reflects the absence of exploration expense in the Full Cost Method of Accounting. In calculating Adjusted EBITDA/EBITDAX, gains/losses on commodity derivatives not designated as hedges and net cash received or paid in settlement of derivative instruments are also excluded. Other excluded items include interest income, gain on sale of assets, restructuring, reorganization and other expense. Adjusted EBITDA/EBITDAX is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA/EBITDAX 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/EBITDAX to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP.

	Three Months Ended March 31,
Adjusted EBITDA/EBITDAX (in thousands)	Successor			Predecessor
	2017			2016
Net loss (US GAAP)	$	(5,725	)	$	(18,733	)
Exploration expense	—			197
Interest expense	2,179			8,313
Depreciation, depletion and amortization	2,294			3,145
Share based compensation expense	1,728			1,070
(Gain) loss on commodity derivatives not designated as hedges	260			(24		)
Net cash received in settlement of derivative instruments	142			—
Other items (1)	(204		)	3,633
Adjusted EBITDA/EBITDAX	$	674		$	(2,399	)

(1) Other items include interest income, gain on sale of assets, restructuring, reorganization and other 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. Our computations of Adjusted EBITDA/EBITDAX may not be comparable to other similarly totaled measures of other companies.

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Liquidity and Capital Resources

Overview

Our primary sources of cash during the first quarter of 2017 were cash on hand and cash from operating activities. We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 2017 through a combination of cash on hand and cash from operating activities, although we may from time to time consider the funding alternatives described below.

We exited the first quarter of 2017 with cash on hand of $37.9 million. As of March 31, 2017, we had outstanding debt under the Exit Credit Facility of $16.7 million which matures at the earliest in September 2018 and $42.6 million Convertible Second Lien Notes outstanding, which matures at the earliest in August, 2019.

Our total capital expenditure budget for 2017 is expected to range between $40 million to $50 million. We plan to focus all our 2017 drilling efforts in the Haynesville Shale Trend.

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:

• sale of non-core assets;

• joint venture partnerships in our TMS, Eagle Ford Shale Trend, and/or core Haynesville Shale Trend acreage;

• entering into a replacement bank credit facility; and

• issuance of debt or equity securities.

We have supported our cash flows with derivative contracts which covered approximately 38% of our natural gas sales volumes for the first quarter of 2017. We had no oil derivative contracts for the first quarter of 2017. See Note 6-“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 presents our comparative cash flow summary for the periods reported (in thousands):

	Three Months Ended March 31,
	Successor			Predecessor
	2017			2016
Cash flow statement information:
Net cash:
Provided by (used in) operating activities	$	4,665		$	(10,488	)
Used in investing activities	(3,384		)	(717		)
(Used in) provided by financing activities	(182		)	12,103
Increase in cash and cash equivalents	$	1,099		$	898

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. Changes in working capital also impact cash flows. Net cash provided by operating activities for the three months ended March 31, 2017 was $4.7 million including operating cash flows before working capital changes of $0.4 million.

Investing activities: We recorded capital expenditures of approximately $6.3 million, which includes $0.6 million of capitalized internal costs directly related to our acquisition of leasehold, drilling and completion activities. Net cash used in investing activities was $3.4 million for the three months ended March 31, 2017, with the difference attributed to the $3.2 million accrued at March 31, 2017 and the utilization of $0.3 million of cash advanced in 2016, offset by the $0.6 million accrued at December 31, 2016 and paid in the first quarter of 2017. Capital expenditures for the quarter were comprised of $6.1 million associated with drilling and completions costs and $0.2 million for miscellaneous expenditures.

Financing activities: Net cash used in financing activities for the three months ended March 31, 2017 consisted of $0.2 million in registration cost associated with various securities issued since our emergence from bankruptcy.

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

	March 31, 2017				December 31, 2016
	Principal		Carrying Amount		Principal		Carrying Amount
Exit Credit Facility	$	16,651	$	16,651	$	16,651	$	16,651
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	42,559		32,481		41,170		30,554
Total debt	$	59,210	$	49,132	$	57,821	$	47,205

⁽¹⁾ The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes $2.6 million and $1.2 million of paid in-kind interest at March 31, 2017 and December 31, 2016, respectively. The carrying value includes $10.1 million and $10.6 million of unamortized debt discount at March 31, 2017 and December 31, 2016, respectively.

For additional information on our financing activities, see Note 3 – “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, 2016, includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three months ended March 31, 2017.

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 counterparties 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 3—“Debt”and Note 6—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.

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 entered into natural gas derivative instruments during the three months ended March 31, 2017 in order to reduce the price risk associated with production in the first quarter of 2017 of approximately 12,000 MMBtu per day. We did not enter into derivatives instruments for trading purposes. Utilizing actual derivative contractual volumes, a hypothetical 10% increase in underlying commodity prices would have increased the derivative liability position, while a hypothetical 10% decrease in underlying commodity prices would have decreased the derivative liability. The aforementioned decrease and increase in the net derivative liability position would have been de minimis to our consolidated financial statements as of March 31, 2017. Furthermore, a gain or loss would have been

24

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, 2016.

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 March 31, 2017, 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.

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 1—“Description of Business and Significant Accounting Policies” and Note 7—“Commitments and Contingencies” to the Notes to Consolidated Financial Statements and Part I, Item II under “—Emergence from Bankruptcy” in this Quarterly Report on Form 10-Q.

As of March 31, 2017, 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, 2016, 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.

25

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).
10.1*	First Amendment and Consent to Exit Credit Agreement dated as of December 22, 2016 among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto.
10.2*	Second Amendment to Exit Credit Agreement dated as of March 31, 2017 among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto.
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

26

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: May 9, 2017	By:	/S/ Walter G. Goodrich
		Walter G. Goodrich
		Chairman & Chief Executive Officer
Date: May 9, 2017	By:	/S/ Robert T. Barker
		Robert T. Barker
		Vice President, Controller, Chief Accounting Officer and Chief Financial Officer

27

EX-10.1

Execution Version

FIRST AMENDMENT AND CONSENT

TO

EXIT CREDIT AGREEMENT

dated as of

December 22, 2016

among

GOODRICH PETROLEUM CORPORATION,

as Parent Guarantor,

GOODRICH PETROLEUM COMPANY, L.L.C.,

as Borrower,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent,

and

The Lenders Party Hereto

WELLS FARGO SECURITIES, LLC,

as Sole Lead Arranger and Sole Bookrunner

1

18934312.5

FIRST AMENDMENT AND CONSENT TO EXIT CREDIT AGREEMENT

THIS FIRST AMENDMENT AND CONSENT TO EXIT CREDIT AGREEMENT (this “Amendment”), dated as of December 22, 2016 is among GOODRICH PETROLEUM CORPORATION, a Delaware corporation (the “Parent Guarantor”); GOODRICH PETROLEUM COMPANY, L.L.C., a Louisiana limited liability company (the “Borrower”); WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”) for the lenders party to the Credit Agreement (collectively, the “Lenders”); and the Lenders party hereto.

R E C I T A L S

A.    The Parent Guarantor, the Borrower, the Administrative Agent and the Lenders are parties to that certain Exit Credit Agreement dated as of October 12, 2016 (as amended, supplemented, amended and restated or otherwise modified from time to time, the “Credit Agreement”), pursuant to which the Lenders have made certain loans to and other extensions of credit on behalf of the Borrower.

B.    The Parent Guarantor wishes to issue common Equity Interests for aggregate proceeds not to exceed $25,000,000 (the “Equity Issuance”).

C.    The Borrower has requested that the Administrative Agent and the Lenders consent to a waiver of or amend certain provisions of the Credit Agreement as more fully described herein.

D.    The Administrative Agent and the Lenders are willing to grant such consent and amendment subject to the terms and conditions set forth herein.

E.    NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Amendment. Unless otherwise indicated, all article and section references in this Amendment refer to articles and sections of the Credit Agreement.

Section 2.Waiver to Credit Agreement. Notwithstanding any rights and remedies the Administrative Agent and the Lenders have under the Credit Agreement and the other Loan Documents, effective as of the Amendment Closing Date (as defined below), the Administrative Agent and the Lenders hereby waive, solely in connection with the Equity Issuance, the requirement in Section 3.04(e) of the Credit Agreement that the Borrower prepay the Borrowings in an aggregate principal amount equal to the net cash proceeds of any issuance of any Equity Interests by the Parent Guarantor within one (1) Business Day of such issuance.

1

18934312.5

Section 3.Amendments to Credit Agreement. Effective as of the Amendment Closing Date:

(a)the following definitions are added to Section 1.02 of the Credit Agreement in appropriate alphabetical order:

“Equity Issuance Net Proceeds” means an amount equal to the net cash proceeds of the Equity Issuance (as such term is defined in the First Amendment and Consent) after deducting customary reasonable costs, expenses and fees in connection with such issuance minus $2,500,000.”

“First Amendment and Consent” means the First Amendment and Consent to Exit Credit Agreement dated as of December [ ], 2016 among, the Parent Guarantor, the Borrower, the Administrative Agent for the Lenders and the Lenders party thereto.”

(b)clause (v) of the definition of “Maturity Date” is hereby amended by deleting “$15,000,000” and replacing it with “$10,000,000”;

(c)Section 3.04(d) of the Credit Agreement is amended in its entirety to the following:

“(d)    If (i) there are outstanding Borrowings and (ii) (A) on or before March 31, 2018, the Consolidated Cash Balance at the end of any Business Day exceeds the sum of (1) $27,500,000 plus (2) an amount equal to the Equity Issuance Net Proceeds or (B) on or after April 1, 2018, the Consolidated Cash Balance at the end of any Business Day exceeds $7,500,000, then the Borrower shall, within one Business Day, prepay the Borrowings in an aggregate principal amount equal to such excess.”; and

(d)Section 9.21 of the Credit Agreement is amended by deleting the amount “$27,500,000” and replacing it with the phrase “the sum of $27,500,000 plus an amount equal to the Equity Issuance Net Proceeds”.

Section 4.Conditions Precedent. This Amendment shall not be deemed to be effective until the date on which each of the following conditions is satisfied (or waived by each Lender) (the “Amendment Closing Date”):

(a)The Administrative Agent shall have received from each of the Lenders, the Borrower and the Parent Guarantor, counterparts (in such number as may be requested by Administrative Agent) of this Amendment signed on behalf of such Persons.

(b)The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the date hereof, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses (including, without limitation,

2

18934312.5

the fees and expenses of counsel to the Administrative Agent) required to be reimbursed or paid by the Borrower under the Credit Agreement.

(c)The Administrative Agent shall have received such documents as the Administrative Agent or special counsel to Administrative Agent may reasonably request.

(d)The Equity Issuance shall have occurred.

(e)The Administrative Agent shall have received, on behalf of the Lenders, a prepayment on the Borrowings in an amount equal to $2,500,000.

(f)Each of the representations and warranties contained in the Credit Agreement and the other Loan Documents shall be true and correct in all material respects (except that any representation and warranty that is qualified as to “materiality” or “Material Adverse Effect” shall be true and correct in all respects) on and as of the Amendment Closing Date, except to the extent such representations and warranties expressly related to any earlier date.

(g)No Default or Event of Default has occurred and is then continuing.

The Administrative Agent is hereby authorized and directed to declare this Amendment to be closed when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 4. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes. Notwithstanding the foregoing, if the Amendment Closing Date hereunder has not occurred on or before 5:00 p.m., Houston, Texas time, on April 1, 2017, each of Section 2 and Section 3 hereof shall be of no force and effect

Section 5.Credit Agreement; No Further Modification. As a condition to the occurrence and continuation of the amendment and waiver provided herein by the Administrative Agent and the Lenders, the Borrower and the Parent Guarantor hereby agree to continue to be bound by, and comply with, the terms and conditions of the Credit Agreement at all times and in all respects. Except as specifically provided herein, all terms, conditions and covenants contained in the Credit Agreement, and all rights of the Administrative Agent and the Lenders with respect thereto, shall remain in full force and effect.

Section 6.Representations and Warranties. As of the date hereof, each of the Borrower and the Parent Guarantor represents and warrants to the Administrative Agent and each of the Lenders that:

(a)The execution, delivery and performance of this Amendment by each of the Borrower and the Parent Guarantor are within such Person’s powers and have been duly authorized by all necessary action on the part of such Person. This Amendment has been duly executed and delivered by each of the Borrower and the Parent Guarantor and constitutes a legal, valid and binding obligation of such Person, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

3

18934312.5

(b)The execution, delivery and performance of this Amendment by each of the Borrower and the Parent Guarantor (i) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including shareholders or any class of directors, whether interested or disinterested, of the Borrower or any other Person), nor is any such consent, approval, registration, filing or other action necessary for the consummation of the transactions contemplated thereby, except (A) such as have been obtained or made and are in full force and effect, (B) the recording and filing of the Security Instruments as required by the Credit Agreement, (C) those third party approvals or consents which, if not made or obtained, would not cause a Default under the Credit Agreement, could not reasonably be expected to have a Material Adverse Effect or do not have an adverse effect on the enforceability of the Loan Documents and (D) the filing of any document with the SEC, (ii) will not violate any applicable law or regulation in any material respect or the charter, by-laws or other organizational documents of the Parent Guarantor or the Borrower or any order of any Governmental Authority, (iii) will not violate or result in a default under any material agreement or other instrument binding upon the Parent Guarantor or the Borrower or its Properties, or give rise to a right thereunder to require any payment to be made by the Parent Guarantor or the Borrower and (iv) will not result in the creation or imposition of any Lien on any Property of the Parent Guarantor or the Borrower (other than the Liens created by the Loan Documents).

(c)Each of the representations and warranties contained in the Credit Agreement and the other Loan Documents is true and correct in all material respects (except that any representation and warranty that is qualified as to “materiality” or “Material Adverse Effect” shall be true and correct in all respects) on and as of the date hereof, except to the extent such representations and warranties expressly related to any earlier date.

(d)No Default or Event of Default has occurred or is continuing or would reasonably be expected to result after giving effect to this Amendment or any other transaction contemplated hereby.

Section 7.Ratification of Liability. The Borrower and the Parent Guarantor, as debtors, grantors, pledgors, guarantors, assignors, or in other similar capacities in which such parties grant liens or security interests in their properties or otherwise act as accommodation parties or guarantors, as the case may be, under the Loan Documents, hereby ratify and reaffirm all of their payment and performance obligations and obligations to indemnify, contingent or otherwise, under each of such Loan Documents to which it is a party, and ratify and reaffirm their grants of liens on or security interests in their properties pursuant to such Loan Documents to which they are a party, respectively, as security for the obligations under the Loan Documents, and each such Person hereby confirms and agrees that such liens and security interests hereafter secure all of the obligations under the Loan Documents.

Section 8.Reference to and Effect upon the Credit Agreement.

(a)Except as specifically amended and waived hereby, all terms, conditions, covenants, representations and warranties contained in the Credit Agreement and other Loan Documents, and all rights of the Administrative Agent and the Lenders and all of the obligations under the Loan Documents, shall remain in full force and effect. The Borrower and the Parent

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18934312.5

Guarantor hereby confirm that the Credit Agreement and the other Loan Documents are in full force and effect and that neither the Borrower nor the Parent Guarantor has any right of setoff, recoupment or other offset or any defense, claim or counterclaim with respect to any of the obligations under the Loan Documents, the Credit Agreement or any other Loan Document.

(b)Except as expressly set forth herein, the execution, delivery and effectiveness of this Amendment shall not directly or indirectly (i) except as expressly set forth in Section 2 hereof, and only to such extent, constitute a consent or waiver of the provisions of the Credit Agreement or any other Loan Documents nor constitute a novation of any of the obligations under the Loan Documents under the Credit Agreement or other Loan Documents or (ii) constitute a course of dealing or other basis for altering any obligations under the Loan Documents or any other contract or instrument. Except as expressly set forth herein, the Administrative Agent and each Lender reserves all of its rights, powers, and remedies under the Credit Agreement, the other Loan Documents and applicable law.

(c)From and after the Amendment Closing Date, (i) the term “Agreement” in the Credit Agreement, and all references to the Credit Agreement in any other Loan Document, shall mean the Credit Agreement, as modified hereby, and (ii) the term “Loan Documents” in the Credit Agreement and the other Loan Documents shall include, without limitation, this Amendment and any agreements, instruments and other documents executed and/or delivered in connection herewith.

(d)The Borrower and the Parent Guarantor acknowledge and agree that the Administrative Agent’s and Lenders’ agreement to provide the waiver set forth in Section 2 hereof does not in any manner whatsoever limit the Administrative Agent’s or any Lender’s right to insist upon strict compliance by the Borrower and the Parent Guarantor with the Credit Agreement, this Amendment or any other Loan Document.

(e)This Amendment shall not be deemed or construed to be a satisfaction, reinstatement, novation or release of the Credit Agreement or any other Loan Document.

Section 9.Release. The Borrower and the Parent Guarantor, in consideration of the Administrative Agent’s and the Lenders’ execution and delivery of this Amendment and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, unconditionally, freely, voluntarily and, after consultation with counsel and becoming fully and adequately informed as to the relevant facts, circumstances and consequences, releases, waives and forever discharges (and further agrees not to allege, claim or pursue) any and all claims, rights, causes of action, counterclaims or defenses of any kind whatsoever, in contract, in tort, in law or in equity, whether known or unknown, direct or derivative, which the Borrower, the Parent Guarantor or any predecessor, successor or assign might otherwise have or may have against the Administrative Agent, the Lenders, their present or former subsidiaries and affiliates or any of the foregoing’s officers, directors, employees, attorneys or other representatives or agents in each case on account of any conduct, condition, act, omission, event, contract, liability, obligation, demand, covenant, promise, indebtedness, claim, right, cause of action, suit, damage, defense, circumstance or matter of any kind whatsoever which existed, arose or occurred at any time prior to the Amendment Closing Date relating to the Loan Documents, this Amendment and/or the transactions contemplated thereby

5

18934312.5

or hereby. The foregoing release shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Commitments or the termination of the Credit Agreement, this Amendment, any other Loan Document or any provision hereof or thereof.

Section 10.Counterparts. This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Amendment by facsimile or electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

Section 11.NO ORAL AGREEMENT. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

Section 12.GOVERNING LAW. THIS AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

(SIGNATURES BEGIN NEXT PAGE)

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18934312.5

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first written above.

BORROWER:    GOODRICH PETROLEUM COMPANY, L.L.C.

By: /s/Michael J. Killelea    

Name: Michael J. Killelea

Title: Executive Vice President, General Counsel and Corporate Secretary

PARENT GUARANTOR:    GOODRICH PETROLEUM CORPORATION

By: /s/Michael J. Killelea    

Name: Michael J. Killelea

Title: Executive Vice President, General Counsel and Corporate Secretary

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

ADMINISTRATIVE AGENT: WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and as a Lender

By: /s/Stephanie Harrell    

Name:    Stephanie Harrell
Title: Vice President

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: BANK OF MONTREAL, as a Lender

By: /s/Emily Steckel    

Name:    Emily Steckel
Title: Assistant Vice President

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: COMPASS BANK, as a Lender

By: /s/Payton K. Swope    

Name:    Payton K. Swope
Title: Executive Vice President

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: JPMORGAN CHASE. BANK, N.A., as a Lender

By: /s/Darren Vanek    

Name:    Darren Vanek
Title: Executive Director

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: BANK OF AMERICA, N.A., as a Lender

By: /s/Tyler D. Levings    

Name:    Tyler D. Levings
Title: Director

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: ROYAL BANK OF CANADA, as a Lender

By: /s/Leslie P. Vowell    

Name:    Leslie P. VowellTitle: Attorney-in-Fact

Signature Page to First Amendment and Consent to Exit Credit Agreement

18934312.5

LENDER: THE BANK OF NOVA SCOTIA, as a Lender

By: /s/Marc Graham    

Name:    Marc Graham
Title: Director

Signature Page to First Amendment and Consent to Exit Credit Agreement

EX-10.2

Execution Version

SECOND AMENDMENT

TO

EXIT CREDIT AGREEMENT

dated as of

March 31, 2017

among

GOODRICH PETROLEUM CORPORATION,

as Parent Guarantor,

GOODRICH PETROLEUM COMPANY, L.L.C.,

as Borrower,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent,

and

The Lenders Party Hereto

WELLS FARGO SECURITIES, LLC,

as Sole Lead Arranger and Sole Bookrunner

1

SECOND AMENDMENT TO EXIT CREDIT AGREEMENT

THIS SECOND AMENDMENT TO EXIT CREDIT AGREEMENT (this “Amendment”), dated as of March 31, 2017 is among GOODRICH PETROLEUM CORPORATION, a Delaware corporation (the “Parent Guarantor”); GOODRICH PETROLEUM COMPANY, L.L.C., a Louisiana limited liability company (the “Borrower”); WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”) for the lenders party to the Credit Agreement (collectively, the “Lenders”); and the Lenders party hereto.

R E C I T A L S

A.    The Parent Guarantor, the Borrower, the Administrative Agent and the Lenders are parties to that certain Exit Credit Agreement dated as of October 12, 2016 (as amended by that certain First Amendment and Consent to Exit Credit Agreement dated as of December 22, 2016 and as the same may be further amended, supplemented, amended and restated or otherwise modified from time to time, the “Credit Agreement”), pursuant to which the Lenders have made certain loans to and other extensions of credit on behalf of the Borrower.

B.    The Borrower has requested that the Administrative Agent and the Lenders amend certain provisions of the Credit Agreement as more fully described herein.

C.    The Administrative Agent and the Lenders have agreed to such amendments subject to the terms and conditions set forth herein.

D.    NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Amendment. Unless otherwise indicated, all article and section references in this Amendment refer to articles and sections of the Credit Agreement.

Section 2.Amendment to Credit Agreement. Effective as of the Amendment Closing Date:

(a)Section 9.12(i) of the Credit Agreement is amended in its entirety to the following:

“ (i) the sale or other disposition (including Casualty Events) of any Oil and Gas Property or any interest therein or any Subsidiary owning Oil and Gas Properties; provided that (i) 100% of the consideration received in respect of such sale or other disposition shall be cash; provided, however, that the consideration received in respect of any sale or other disposition of undeveloped Haynesville Specified Real Properties may be other Oil and Gas Properties, which shall be equivalent on a net

1

revenue interest acre basis and limited to other undeveloped Haynesville Specified Real Properties to facilitate future development of the field(s), and which will subsequently be mortgaged in accordance with Section 8.19; (ii) the consideration received in respect of such sale or other disposition shall be equal to or greater than the fair market value of the Oil and Gas Property, interest therein or Subsidiary subject of such sale or other disposition (as reasonably determined by the board of directors of the Parent Guarantor and, if requested by the Administrative Agent, the Parent Guarantor shall deliver a certificate of a Responsible Officer certifying to that effect) and (iii) if any such sale or other disposition is of a Subsidiary owning Oil and Gas Properties, such sale or other disposition shall include all the Equity Interests of such Subsidiary; and”.

Section 3.Conditions Precedent. This Amendment shall not be deemed to be effective until the date on which each of the following conditions is satisfied (or waived by the Majority Lenders) (the “Amendment Closing Date”):

(a)The Administrative Agent shall have received from each of the Lenders, the Borrower and the Parent Guarantor, counterparts (in such number as may be requested by Administrative Agent) of this Amendment signed on behalf of such Persons.

(b)The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the date hereof, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses (including, without limitation, the fees and expenses of counsel to the Administrative Agent) required to be reimbursed or paid by the Borrower under the Credit Agreement.

(c)The Administrative Agent shall have received such documents as the Administrative Agent or special counsel to Administrative Agent may reasonably request.

(d)Each of the representations and warranties contained in the Credit Agreement and the other Loan Documents shall be true and correct in all material respects (except that any representation and warranty that is qualified as to “materiality” or “Material Adverse Effect” shall be true and correct in all respects) on and as of the Amendment Closing Date, except to the extent such representations and warranties expressly related to any earlier date.

(e)No Default or Event of Default has occurred and is then continuing.

The Administrative Agent is hereby authorized and directed to declare this Amendment to be closed when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

Section 4.Credit Agreement; No Further Modification. As a condition to the occurrence and continuation of the amendment provided herein by the Administrative Agent and the Lenders, the Borrower and the Parent Guarantor hereby agree to continue to be bound by, and comply with, the terms and conditions of the Credit Agreement at all times and in all respects.

2

Except as specifically provided herein, all terms, conditions and covenants contained in the Credit Agreement, and all rights of the Administrative Agent and the Lenders with respect thereto, shall remain in full force and effect.

Section 5.Representations and Warranties. As of the date hereof, each of the Borrower and the Parent Guarantor represents and warrants to the Administrative Agent and each of the Lenders that:

(a)The execution, delivery and performance of this Amendment by each of the Borrower and the Parent Guarantor are within such Person’s powers and have been duly authorized by all necessary action on the part of such Person. This Amendment has been duly executed and delivered by each of the Borrower and the Parent Guarantor and constitutes a legal, valid and binding obligation of such Person, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)The execution, delivery and performance of this Amendment by each of the Borrower and the Parent Guarantor (i) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including shareholders or any class of directors, whether interested or disinterested, of the Borrower or any other Person), nor is any such consent, approval, registration, filing or other action necessary for the consummation of the transactions contemplated thereby, except (A) such as have been obtained or made and are in full force and effect, (B) the recording and filing of the Security Instruments as required by the Credit Agreement, (C) those third party approvals or consents which, if not made or obtained, would not cause a Default under the Credit Agreement, could not reasonably be expected to have a Material Adverse Effect or do not have an adverse effect on the enforceability of the Loan Documents and (D) the filing of any document with the SEC, (ii) will not violate any applicable law or regulation in any material respect or the charter, by-laws or other organizational documents of the Parent Guarantor or the Borrower or any order of any Governmental Authority, (iii) will not violate or result in a default under any material agreement or other instrument binding upon the Parent Guarantor or the Borrower or its Properties, or give rise to a right thereunder to require any payment to be made by the Parent Guarantor or the Borrower and (iv) will not result in the creation or imposition of any Lien on any Property of the Parent Guarantor or the Borrower (other than the Liens created by the Loan Documents).

(c)Each of the representations and warranties contained in the Credit Agreement and the other Loan Documents is true and correct in all material respects (except that any representation and warranty that is qualified as to “materiality” or “Material Adverse Effect” shall be true and correct in all respects) on and as of the date hereof, except to the extent such representations and warranties expressly related to any earlier date.

(d)No Default or Event of Default has occurred or is continuing or would reasonably be expected to result after giving effect to this Amendment or any other transaction contemplated hereby.

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Section 6.Ratification of Liability. The Borrower and the Parent Guarantor, as debtors, grantors, pledgors, guarantors, assignors, or in other similar capacities in which such parties grant liens or security interests in their properties or otherwise act as accommodation parties or guarantors, as the case may be, under the Loan Documents, hereby ratify and reaffirm all of their payment and performance obligations and obligations to indemnify, contingent or otherwise, under each of such Loan Documents to which it is a party, and ratify and reaffirm their grants of liens on or security interests in their properties pursuant to such Loan Documents to which they are a party, respectively, as security for the obligations under the Loan Documents, and each such Person hereby confirms and agrees that such liens and security interests hereafter secure all of the obligations under the Loan Documents.

Section 7.Reference to and Effect upon the Credit Agreement.

(a)Except as specifically amended hereby, all terms, conditions, covenants, representations and warranties contained in the Credit Agreement and other Loan Documents, and all rights of the Administrative Agent and the Lenders and all of the obligations under the Loan Documents, shall remain in full force and effect. The Borrower and the Parent Guarantor hereby confirm that the Credit Agreement and the other Loan Documents are in full force and effect and that neither the Borrower nor the Parent Guarantor has any right of setoff, recoupment or other offset or any defense, claim or counterclaim with respect to any of the obligations under the Loan Documents, the Credit Agreement or any other Loan Document.

(b)Except as expressly set forth herein, the execution, delivery and effectiveness of this Amendment shall not directly or indirectly (i) constitute a consent or waiver of the provisions of the Credit Agreement or any other Loan Documents nor constitute a novation of any of the obligations under the Loan Documents under the Credit Agreement or other Loan Documents or (ii) constitute a course of dealing or other basis for altering any obligations under the Loan Documents or any other contract or instrument. Except as expressly set forth herein, the Administrative Agent and each Lender reserves all of its rights, powers, and remedies under the Credit Agreement, the other Loan Documents and applicable law.

(c)From and after the Amendment Closing Date, (i) the term “Agreement” in the Credit Agreement, and all references to the Credit Agreement in any other Loan Document, shall mean the Credit Agreement, as modified hereby, and (ii) the term “Loan Documents” in the Credit Agreement and the other Loan Documents shall include, without limitation, this Amendment and any agreements, instruments and other documents executed and/or delivered in connection herewith.

(d)This Amendment shall not be deemed or construed to be a satisfaction, reinstatement, novation or release of the Credit Agreement or any other Loan Document.

Section 8.Release. The Borrower and the Parent Guarantor, in consideration of the Administrative Agent’s and the Lenders’ execution and delivery of this Amendment and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, unconditionally, freely, voluntarily and, after consultation with counsel and becoming fully and adequately informed as to the relevant facts, circumstances and consequences, releases, waives and

4

forever discharges (and further agrees not to allege, claim or pursue) any and all claims, rights, causes of action, counterclaims or defenses of any kind whatsoever, in contract, in tort, in law or in equity, whether known or unknown, direct or derivative, which the Borrower, the Parent Guarantor or any predecessor, successor or assign might otherwise have or may have against the Administrative Agent, the Lenders, their present or former subsidiaries and affiliates or any of the foregoing’s officers, directors, employees, attorneys or other representatives or agents in each case on account of any conduct, condition, act, omission, event, contract, liability, obligation, demand, covenant, promise, indebtedness, claim, right, cause of action, suit, damage, defense, circumstance or matter of any kind whatsoever which existed, arose or occurred at any time prior to the Amendment Closing Date relating to the Loan Documents, this Amendment and/or the transactions contemplated thereby or hereby. The foregoing release shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Commitments or the termination of the Credit Agreement, this Amendment, any other Loan Document or any provision hereof or thereof.

Section 9.Counterparts. This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Amendment by facsimile or electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

Section 10.NO ORAL AGREEMENT. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

Section 11.GOVERNING LAW. THIS AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

(SIGNATURES BEGIN NEXT PAGE)

5

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first written above.

BORROWER:    GOODRICH PETROLEUM COMPANY, L.L.C.

By: /s/Michael J. Killelea    

Name: Michael J. Killelea

Title: Executive Vice President, General Counsel and Corporate Secretary    

PARENT GUARANTOR:    GOODRICH PETROLEUM CORPORATION

By: /s/Michael J. Killelea    

Name: Michael J. Killelea

Title: Executive Vice President, General Counsel and Corporate Secretary    

Signature Page to Second Amendment to Exit Credit Agreement

ADMINISTRATIVE AGENT: WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and as a Lender

By: /s/Stephanie Harrell    

Name:    Stephanie Harrell
Title: Vice President

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: BANK OF MONTREAL, as a Lender

By:

Name:    
Title:    

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: COMPASS BANK, as a Lender

By: /s/Rachel Festervand    

Name:    Rachel Festervand
Title: Sr. Vice President

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: JPMORGAN CHASE. BANK, N.A., as a Lender

By: /s/Trey Lewis    

Name:    Trey Lewis
Title: Authorized Officer

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: BANK OF AMERICA, N.A., as a Lender

By: /s/Tyler D. Levings    

Name:    Tyler D. Levings
Title: Director

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: ROYAL BANK OF CANADA, as a Lender

By: /s/Leslie P. Vowell    

Name:    Leslie P. VowellTitle: Attorney-in-Fact

Signature Page to Second Amendment to Exit Credit Agreement

LENDER: THE BANK OF NOVA SCOTIA, as a Lender

By: /s/Marc Graham    

Name:    Marc Graham
Title: Director

Signature Page to Second Amendment to Exit Credit Agreement

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 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.

/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 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.

/s/ Robert T. Barker

Robert T. Barker

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 March 31, 2017 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

May 9, 2017

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 Goodrich Petroleum Corporation 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 March 31, 2017 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

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

May 9, 2017

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 Goodrich Petroleum Corporation and will be retained by it and furnished to the Securities and Exchange Commission or its staff upon request.

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 09, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Trading Symbol	GDP
Entity Registrant Name	GOODRICH PETROLEUM CORP
Entity Central Index Key	0000943861
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		9,108,826

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Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 37,949	$ 36,850
Accounts receivable, trade and other, net of allowance	260	1,998
Accrued oil and natural gas revenue	3,841	3,142
Inventory	4,008	4,125
Prepaid expenses and other	374	755
Total current assets	46,432	46,870
PROPERTY AND EQUIPMENT:
Unevaluated properties	13,367	24,206
Oil and natural gas properties (full cost method)	78,047	60,936
Furniture, fixtures and equipment	986	984
Property, Plant and Equipment, Gross	92,400	86,126
Less: Accumulated depletion, depreciation and amortization	(6,245)	(4,006)
Net property and equipment	86,155	82,120
Other	723	322
TOTAL ASSETS	133,310	129,312
Accounts payable
Accounts payable	16,256	14,392
Accrued liabilities	8,094	3,882
Fair value of commodity derivatives	804	0
Total current liabilities	25,154	18,274
Long term debt, net	49,132	47,205
Accrued abandonment cost	3,023	2,933
Total liabilities	77,309	68,412
Commitments and contingencies (See Note 7)
STOCKHOLDERS’ EQUITY:
Common stock: $0.01 par value, 75,000,000 shares authorized, and 9,108,826 shares issued and outstanding	91	91
Additional paid in capital	65,942	65,116
Accumulated deficit	(10,032)	(4,307)
Total stockholders’ equity	56,001	60,900
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 133,310	$ 129,312

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	75,000,000	75,000,000
Common stock, shares issued	9,108,826	9,108,826
Common stock, shares outstanding	9,108,826	9,108,826

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Consolidated Statements Of Operations (Unaudited) - USD ($) shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OTHER INCOME (EXPENSE):
Income tax benefit	$ 0
Successor [Member]
REVENUES:
Oil and natural gas revenues	9,411,000
Other	2,000
Total revenues	9,413,000
OPERATING EXPENSES:
Lease operating expense	4,311,000
Production and other taxes	659,000
Transportation and processing	1,176,000
Depreciation, depletion and amortization	2,294,000
Exploration	0
General and administrative	4,463,000
Gain on sale of assets	0
Operating Expenses, Total	12,903,000
Operating loss	(3,490,000)
OTHER INCOME (EXPENSE):
Interest expense	(2,179,000)
Interest income and other	9,000
(Loss)/gain on derivatives not designated as hedges	(260,000)
Nonoperating Income (Expense), Total	(2,430,000)
Restructuring	0
Reorganization items, net	195,000
Loss before income taxes	(5,725,000)
Income tax benefit	0
Net loss	(5,725,000)
Preferred stock, net	0
Net loss applicable to common stock	$ (5,725,000)
PER COMMON SHARE
Net loss applicable to common stock - basic (in dollars per share)	$ (0.63)
Net loss applicable to common stock - diluted (in dollars per share)	$ (0.63)
Weighted average common shares outstanding - basic (shares)	9,109
Weighted average common shares outstanding - diluted (shares)	9,109
Predecessor [Member]
REVENUES:
Oil and natural gas revenues		$ 6,464,000
Other		(219,000)
Total revenues		6,245,000
OPERATING EXPENSES:
Lease operating expense		2,336,000
Production and other taxes		739,000
Transportation and processing		431,000
Depreciation, depletion and amortization		3,145,000
Exploration		197,000
General and administrative		6,364,000
Gain on sale of assets		(837,000)
Operating Expenses, Total		12,375,000
Operating loss		(6,130,000)
OTHER INCOME (EXPENSE):
Interest expense		(8,313,000)
Interest income and other		0
(Loss)/gain on derivatives not designated as hedges		24,000
Nonoperating Income (Expense), Total		(8,289,000)
Restructuring		(4,314,000)
Reorganization items, net		0
Loss before income taxes		(18,733,000)
Income tax benefit		0
Net loss		(18,733,000)
Preferred stock, net		1,004,000
Net loss applicable to common stock		$ (19,737,000)
PER COMMON SHARE
Net loss applicable to common stock - basic (in dollars per share)		$ (0.26)
Net loss applicable to common stock - diluted (in dollars per share)		$ (0.26)
Weighted average common shares outstanding - basic (shares)		74,521
Weighted average common shares outstanding - diluted (shares)		74,521

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Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM FINANCING ACTIVITIES:
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	$ 36,850
CASH AND CASH EQUIVALENTS, END OF PERIOD	37,949
Successor [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	(5,725)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	2,294
Loss/(gain) on commodity derivatives not designated as hedges	260
Net cash received in settlement of commodity derivative instruments	142
Amortization of leasehold costs	0
Share based compensation (non-cash)	1,008
Bonus share based compensation (non-cash)	720
Gain on sale of assets	0
Embedded derivative	0
Amortization of finance cost, debt discount, paid in-kind interest and accretion	1,927
Materials inventory write-down	0
Reorganization items, net	(181)
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance	1,738
Accrued oil and natural gas revenue	(699)
Inventory	0
Prepaid expenses and other	88
Accounts payable	1,864
Accrued liabilities	1,229
Net cash provided by (used in) operating activities	4,665
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(3,384)
Proceeds from sale of assets	0
Net cash used in investing activities	(3,384)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings	0
Payments related to Convertible Second Lien Notes	(36)
Note conversions	0
Registration costs	(146)
Other	0
Net cash (used in) provided by financing activities	(182)
INCREASE IN CASH AND CASH EQUIVALENTS	1,099
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	36,850
CASH AND CASH EQUIVALENTS, END OF PERIOD	37,949
Supplemental disclosures of cash flow information:
Cash paid for Interest	$ 309
Predecessor [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$ (18,733)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		3,145
Loss/(gain) on commodity derivatives not designated as hedges		(24)
Net cash received in settlement of commodity derivative instruments		0
Amortization of leasehold costs		24
Share based compensation (non-cash)		1,070
Bonus share based compensation (non-cash)		0
Gain on sale of assets		(837)
Embedded derivative		(3,845)
Amortization of finance cost, debt discount, paid in-kind interest and accretion		4,329
Materials inventory write-down		156
Reorganization items, net		0
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		892
Accrued oil and natural gas revenue		419
Inventory		(512)
Prepaid expenses and other		735
Accounts payable		(3,867)
Accrued liabilities		6,560
Net cash provided by (used in) operating activities		(10,488)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(1,006)
Proceeds from sale of assets		289
Net cash used in investing activities		(717)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings		13,000
Payments related to Convertible Second Lien Notes		0
Note conversions		(804)
Registration costs		(88)
Other		(5)
Net cash (used in) provided by financing activities		12,103
INCREASE IN CASH AND CASH EQUIVALENTS		898
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		11,782
CASH AND CASH EQUIVALENTS, END OF PERIOD		12,680
Supplemental disclosures of cash flow information:
Cash paid for Interest		$ 451

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Description of Business and Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Description of Business and Significant Accounting Policies

Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (together with its 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 (the “SEC”) 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, 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year or for any interim period. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period.

Fresh Start Accounting—We applied fresh start accounting upon emergence from bankruptcy on October 12, 2016 (the "Effective Date"). This resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. As a result, our consolidated statement of operations subsequent to the Effective Date are not comparable to our consolidated statement of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented in a format that illustrates the lack of comparability between amounts presented on or after October 12, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

All references made to "Successor" or "Successor Company" relate to the Company on and subsequent to the Effective Date. References to the “Successor" in this quarterly report relate to the periods after October 12, 2016 which includes the first quarter of 2017. References to "Predecessor" or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date which includes the first quarter of 2016.

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.

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 March 31, 2017 and December 31, 2016:

(In thousands)	March 31, 2017		December 31, 2016
Trade payables	$	4,522	$	2,004
Revenue payable	11,101		11,296
Prepayments from partners	496		965
Miscellaneous payables	137		127
Total accounts payable	$	16,256	$	14,392

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. Upon emergence from bankruptcy, we elected to adopt the Full Cost Method.

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. 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.

We amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. This entails the quarterly provision for DD&A expense being computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and natural gas properties and future development costs.

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 quarter ended March 31, 2017.

Impairment—Prior to October 12, 2016 under the Successful Efforts Method of Accounting, we periodically assessed our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they were not overstated or carried in excess of fair value, which was computed using Level 3 inputs such as discounted cash flow models or valuations. Significant Level 3 assumptions associated with discounted cash flow models or valuations used in the impairment evaluation included estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation was performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicated that our oil and natural gas properties may be impaired.

To determine if a field was impaired, we compared the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves were taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. For each property determined to be impaired, we recognized an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.

Fair value was estimated to be the present value of expected future net cash flows. Any impairment charge incurred was recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this

calculation was subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash

flows and fair value.

We had no impairment for the quarter ended March 31, 2016.

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 nonperformance, 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 which are derived principally from or corroborated by observable market data. Included in this Level are our Exit Credit Facility 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 counterparties; 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 acquisitions and impairments of oil and natural gas properties, if any, and our asset retirement obligations.

As of March 31, 2017 and December 31, 2016, 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.

Depreciation and Depletion—Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.

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.

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 2.

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 measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Revenue Recognition—Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. 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. AtMarch 31, 2017and December 31, 2016, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. 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 counterparty 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 6.

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 bases 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 5.

Net Income or Net Loss Per Share—Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted average number of common shares 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 4.

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 7.

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. The fair value of each restricted stock award is measured using the closing price of our common stock on the day of the award.

New Accounting Pronouncements

On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the amendments are effective for annual periods beginning after December 15, 2016. We adopted this standard in 2017 and anticipate no material impact on our consolidated financial statements until the fourth quarter of 2017, when the initial vestings of restricted stock issued under our Management Incentive Plan occur.

On February 25, 2016 the FASB issued ASU 2016-02, Leases (Topic 842). The key difference between the existing standards and ASU 2016-02 is the requirement for lessees to recognize on their balance sheet all lease contracts with lease terms greater than 12 months, including operating leases. Specifically, lessees are required to recognize on the balance sheet at lease commencement, both (i) a right-of-use asset, representing the lessee’s right to use the leased asset over the term of the lease, and (ii) a lease liability, representing the lessee’s contractual obligation to make lease payments over the term of the lease. For lessees, ASU 2016-02 requires classification of leases as either operating or finance leases, which are similar to the current operating and capital lease classifications. However, the distinction between these two classifications under the ASU does not relate to balance sheet treatment, but relates to treatment and recognition in the statements of income and cash flows. Lessor accounting is largely unchanged from current US GAAP. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, for public entities. Early application is permitted. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2017 is as follows (in thousands):

	March 31, 2017
Beginning balance at December 31, 2016	$	2,933
Liabilities incurred	35
Accretion expense	55
Ending balance at March 31, 2017	$	3,023
Current liability	$	—
Long term liability	$	3,023

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Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Debt

Debt

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

	March 31, 2017				December 31, 2016
	Principal		Carrying Amount		Principal		Carrying Amount
Exit Credit Facility	$	16,651	$	16,651	$	16,651	$	16,651
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	42,559		32,481		41,170		30,554
Total debt	$	59,210	$	49,132	$	57,821	$	47,205

⁽¹⁾ The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes $2.6 million and $1.2 million of paid in-kind interest at March 31, 2017 and December 31, 2016, respectively. The carrying value includes $10.1 million and $10.6 million of unamortized debt discount at March 31, 2017 and December 31, 2016, respectively.

The following table summarizes the total interest expense for the periods shown including contractual interest expense, amortization of debt discount, accretion and financing costs and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates).

	Successor				Predecessor
	March 31, 2017				March 31, 2016
	Interest Expense		Effective Interest Rate		Interest Expense		Effective Interest Rate
Successor Exit Credit Facility	$	252	6.1	%	$	—	—	%
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	1,927		24.2	%	—		—	%
Predecessor Senior Credit Facility	—		—	%	870		7.2	%
8.0% Second Lien Senior Secured Notes due 2018 **	—		—	%	1,109		18.7	%
8.875% Senior Notes due 2019	—		—	%	2,688		9.1	%
3.25% Convertible Senior Notes due 2026	—		—	%	3		3.3	%
5.0% Convertible Senior Notes due 2029	—		—	%	84		5.0	%
5.0% Convertible Senior Notes due 2032	—		—	%	2,053		8.4	%
5.0% Convertible Exchange Senior Notes due 2032	—		—	%	1,484		*
Other	—		—	%	22		*
Total debt	$	2,179			$	8,313

(1) Interest expense for the period ended Mach 31, 2017 includes $0.5 million of debt discount amortization and $1.4 million of paid in-kind interest.

* - Not meaningful.

** - Includes $3.8 million gain from the change in fair value of the embedded derivative associated with the 8.0% Second Lien Notes.

Exit Credit Facility

On October 12, 2016, upon consummation of the plan of reorganization, the Company entered into an Exit Credit Agreement (the “Exit Credit Agreement”) with the Subsidiary, as borrower (the “Borrower”), and Wells Fargo Bank, National Association, as administrative agent (“the Administrative Agent”), and certain other lenders party thereto. Pursuant to the Exit Credit Agreement, the lenders party thereto agreed to provide the Borrower with a $20.0 million senior secured term loan credit facility (the “Exit Credit Facility”), with available borrowing capacity of $20.0 million. As of March 31, 2017, we had $16.7 million outstanding on the Exit Credit Facility.

The maturity date of the Exit Credit Agreement is September 30, 2018, unless the Borrower notifies the Administrative Agent that it intends to extend the maturity date to September 30, 2019, subject to certain conditions and the payment of a fee.

Until such maturity date, the Loans (as defined in the Exit Credit Agreement) under the Exit Credit Agreement shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 4.50% or (ii) adjusted LIBOR plus an applicable margin of 5.50%. As of March 31, 2017, the interest rate on the Exit Credit Facility was 6.53%.

The Borrower may elect, at its option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement).

The Borrower may be required to make mandatory prepayments of the Loans under the Exit Credit Agreement if the total borrowings exceed the aggregate credit amounts, and if the Borrower is not in compliance with the Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) or the Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement).

Additionally, if the Borrower has outstanding borrowings and the Consolidated Cash Balance (as defined in the Exit Credit Agreement and the First Amendment and Consent to Exit Credit Agreement dated December 22, 2016) exceeds (i) the sum of $27.5 million plus $21.3 million, which is calculated as the Equity Issuance Net Proceeds from the December 19, 2016 private placement less $2.5 million, as of the close of business on the most recently ended business day on or before March 31, 2018 or (ii) $7.5 million as of the close of business on the most recently ended business day on or after April 1, 2018, the Borrower may also be required to make mandatory prepayments in an aggregate principal amount equal to such excess.

Furthermore, the Borrower is required to make certain mandatory prepayments within one business day of (i) the issuance of any Equity Interests (as defined in the Exit Credit Agreement) of the Company, (ii) the consummation of any sale or other disposition of Property (as defined in the Exit Credit Agreement) and (iii) the assignment, termination or unwinding of any Swap Agreements (as defined in the Exit Credit Agreement).

Amounts outstanding under the Exit Credit Agreement are guaranteed by the Company and secured by a security interest in substantially all of the assets of the Company and the Borrower.

The Exit Credit Agreement contains certain customary representations and warranties, including as to organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; subsidiaries; location of business and offices; properties; titles, etc.; maintenance of properties; gas imbalances, prepayments; marketing of production; swap agreements; use of loans; solvency; sanctions laws and regulations; foreign corrupt practices; money laundering laws; and embargoed persons.

The Exit Credit Agreement also contains certain affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments; and swap agreements.

The Exit Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.5 to 1.0 initially, and increasing to 2.0 to 1.0 or after December 31, 2018, (ii)  Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.10 to 1.00 initially, and increasing to 1.35 to 1.00 and 1.50 to 1.00 after March 31, 2017 and September 30, 2017, respectively, in the case of clauses (i) and (ii), to be determined as of January 1 and July 1 each year and as of the date of any Material Acquisition (as defined in the Exit Credit Agreement) or Material Disposition (as defined in the Exit Credit Agreement), (iii) commencing with the fiscal quarter ending March 31, 2018, a ratio of Debt (as defined in the Exit Credit Agreement) as of the end of each fiscal quarter to EBITDAX for the twelve months ending on the last day of such fiscal quarter, not to exceed 4.00 to 1.00, (iv) limitations on Consolidated Cash Balance, (v) limitations on general and administrative expenses and (vi) minimum liquidity requirements.

The Exit Credit Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; voluntary and involuntary bankruptcy; judgments; and change of control.

As of March 31, 2017, we were in compliance with all covenants within the Exit Credit Agreement.

13.50% Convertible Second Lien Senior Secured Notes Due 2019

On October 12, 2016, the Company and the Subsidiary, entered into a purchase agreement (the “Purchase Agreement”) with each entity identified as a Shenkman Purchaser on Appendix A to the Purchase Agreement (collectively, the “Shenkman Purchasers”), CVC Capital Partners (acting through such of its affiliates to managed funds as it deems appropriate), J.P. Morgan Securities LLC (acting through such of its affiliates or managed funds as it deems appropriate), Franklin Advisers, Inc. (as investment manager on behalf of certain funds and accounts), O’Connor Global Multi-Strategy Alpha Master Limited and Nineteen 77 Global Multi-Strategy Alpha (Levered) Master Limited (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 is convertible at the option of the Purchasers at any time prior to the scheduled maturity date into an amount of the Company’s common stock equal to 15% of the common stock of the reorganized Company on a fully diluted basis, subject to adjustments. At closing, the Purchasers were issued 10-year costless warrants for common stock equal to 20% of the New Common Stock of the reorganized Company on a fully diluted basis. Holders of the Convertible Second Lien Notes have a second priority lien on all assets of the Debtors, and have a continuing right to appoint two members to the Board as long as the Convertible Second Lien Notes are outstanding.

The Convertible Second Lien Notes will mature on August 30, 2019, or such later date as set forth in the Convertible Second Lien Notes, but in no event later than March 30, 2020. The Convertible Second Lien 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 Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional Second Lien Notes (“PIK Interest Notes”). The PIK Interest Notes are not convertible. During such time as the Exit Credit Agreement (but not any refinancing or replacement thereof) is in effect, interest on the Convertible Second Lien Notes must be paid in-kind.

The Indenture governing the Convertible Second Lien Notes 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 sale of assets and stock; business activities; transactions with affiliates; and changes of control.

The Indenture also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.10 to 1.00 on or before March 31, 2017 initially and increasing to 1.35 to 1.00 after March 31, 2017 but on or before September 30, 2017 and 1.50 to 1.00 after September 30, 2017, to be determined as of January 1 and July 1 of each year; (ii) limitations on general and administrative expenses and (iii)

minimum liquidity requirements.

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 is amortized using the effective interest rate method based upon an original term through August 30, 2019. $10.1 million of debt discount remains to be amortized on the Convertible Second Lien Notes as of March 31, 2017.

As of March 31, 2017, we were in compliance with all covenants within the Indenture that governs the Convertible Second Lien Notes.

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Net Loss Per Common Share

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Net Loss Per Common Share

Net Loss Per Common Share

Upon our emergence from bankruptcy on October 12, 2016, as discussed in Note 1, the Predecessor Company's outstanding common stock and preferred stock were canceled, and new common stock and warrants were then issued.

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three months ended March 31, 2017 and 2016. The following table sets forth information related to the computations of basic and diluted loss per share.

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
	2017			2016
	(Amounts in thousands, except per share data)
Basic and Diluted loss per share:
Net loss applicable to common stock	$	(5,725	)	$	(19,737	)
Weighted average shares of common stock outstanding	9,109			74,521
Basic and Diluted loss per share (1) (2) (3) (4)	$	(0.63	)	$	(0.26	)
(1) Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid were not presented as they would have been anti-dilutive.	—			16,878
(2) Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Exchange Notes and 2032 Notes or interest paid were not presented as they would have been anti-dilutive.	—			5,910
(3) Common shares issuable on assumed conversion of restricted stock were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	288			13,949
(4) Common shares issuable on the 13.50% Convertible Second Lien Senior Secured Notes due 2019, associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	5,664			—

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

We recorded no income tax expense or benefit for the three months ended March 31, 2017. We recorded a valuation allowance at December 31, 2016 which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, our deferred tax assets were unrecoverable. 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 March 31, 2017.

As of March 31, 2017, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2016.

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Commodity Derivative Activities

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Activities

Commodity Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. 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 months ended March 31, 2017 and 2016:

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
Oil and Natural Gas Derivatives (in thousands)	2017			2016
Gain on commodity derivatives not designated as hedges, settled	$	142		$	—
Gain (loss) on commodity derivatives not designated as hedges, not settled	(402		)	24
Total gain (loss) on commodity derivatives not designated as hedges	$	(260	)	$	24

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 the 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 counterparties. Neither our counterparties nor we require any collateral upon entering derivative contracts. We were not at risk of losing any fair value amounts had our counterparties been unable to fulfill their obligations as of March 31, 2017 and December 31, 2016 because we did not have a net derivative asset on our Consolidated Balance Sheets at those periods.

As of March 31, 2017, the open positions on our outstanding commodity derivative contracts, all of which were natural gas contracts with BP, were as follows:

Contract Type	Daily Volume (MMBtu)	Total Volume (MMBtu)	Fixed Price		Fair Value at March 31, 2017 (In thousands)
Natural Gas Swaps
2017	6,000	1,470,000	$	3.20	$	(182	)
2018	12,000	4,380,000	$3.00 - $3.015		$	(79	)
Natural Gas Costless Collars
2017	12,000	3,300,000	$3.00 - $3.60		$	(141	)

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of March 31, 2017 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.

Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	—		$	—	$	—
Non-current Assets Commodity Derivatives	—		402			—		402
Current Liabilities Commodity Derivatives	—		(804		)	—		(804		)
Non-current Liabilities Commodity Derivatives	—		—			—		—
Total	$	—	$	(402	)	$	—	$	(402	)

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 for the periods ending March 31, 2017 and December 31, 2016:

	March 31, 2017									December 31, 2016
Fair Value of Oil and Natural Gas Derivatives (in thousands)	Gross Amount			Amount Offset			As Presented			Gross Amount		Amount Offset		As Presented
Current Assets Commodity Derivatives	$	336		$	(336	)	$	—		$	—	$	—	$	—
Fair Value of Commodity Derivatives - Other Non-current Assets	413			(11		)	402			—		—		—
Fair Value of Commodity Derivatives - Current Liability	(1,140		)	336			(804		)	—		—		—
Non-current Liabilities Commodity Derivatives	(11		)	11			—			—		—		—
Total	$	(402	)	$	—		$	(402	)	$	—	$	—	$	—

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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, will not be material to our consolidated financial position results of operations or liquidity.

Operating Leases—We have commitments under an operating lease agreement for office space and office equipment. Total rent expense for the three months ended March 31, 2017 and March 31, 2016 was approximately $0.4 million and $0.4 million, respectively.

Defined Contribution Plan – We have a defined contribution plan (“DCP”) which has a Company matching option to employees' contributions. Participation in the DCP is voluntary and all employees of the Company are eligible to participate. We suspended the Company's match in April 2016. We charged to expense plan contributions of zero and $0.1 million for the three months ended March 31, 2017 and March 31, 2016, respectively.

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Description of Business and Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

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 (the “SEC”) 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, 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year or for any interim period. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period.

Fresh Start Accounting—We applied fresh start accounting upon emergence from bankruptcy on October 12, 2016 (the "Effective Date"). This resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. As a result, our consolidated statement of operations subsequent to the Effective Date are not comparable to our consolidated statement of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented in a format that illustrates the lack of comparability between amounts presented on or after October 12, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

All references made to "Successor" or "Successor Company" relate to the Company on and subsequent to the Effective Date. References to the “Successor" in this quarterly report relate to the periods after October 12, 2016 which includes the first quarter of 2017. References to "Predecessor" or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date which includes the first quarter of 2016.

Principles of Consolidation

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.

Use of Estimates

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—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.

Inventory

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

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. Upon emergence from bankruptcy, we elected to adopt the Full Cost Method.

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. 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.

We amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. This entails the quarterly provision for DD&A expense being computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and natural gas properties and future development costs.

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.

Impairment

Impairment—Prior to October 12, 2016 under the Successful Efforts Method of Accounting, we periodically assessed our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they were not overstated or carried in excess of fair value, which was computed using Level 3 inputs such as discounted cash flow models or valuations. Significant Level 3 assumptions associated with discounted cash flow models or valuations used in the impairment evaluation included estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation was performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicated that our oil and natural gas properties may be impaired.

To determine if a field was impaired, we compared the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves were taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. For each property determined to be impaired, we recognized an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.

Fair value was estimated to be the present value of expected future net cash flows. Any impairment charge incurred was recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this

calculation was subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash

flows and fair value.

Fair Value Measurement

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 nonperformance, 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 which are derived principally from or corroborated by observable market data. Included in this Level are our Exit Credit Facility 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 counterparties; 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 acquisitions and impairments of oil and natural gas properties, if any, and our asset retirement obligations.

As of March 31, 2017 and December 31, 2016, 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.

Depreciation

Depreciation and Depletion—Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.

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.

Asset Retirement Obligations

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 2.

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 measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Revenue Recognition

Revenue Recognition—Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. 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. AtMarch 31, 2017and December 31, 2016, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. 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 counterparty 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 6.

Income Taxes

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 bases 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.

Net Income or Net Loss Per Share

Net Income or Net Loss Per Share—Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted average number of common shares 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 4.

Commitments and Contingencies

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.

Share-based Compensation

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. The fair value of each restricted stock award is measured using the closing price of our common stock on the day of the award.

New Accounting Pronouncements

New Accounting Pronouncements

On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the amendments are effective for annual periods beginning after December 15, 2016. We adopted this standard in 2017 and anticipate no material impact on our consolidated financial statements until the fourth quarter of 2017, when the initial vestings of restricted stock issued under our Management Incentive Plan occur.

On February 25, 2016 the FASB issued ASU 2016-02, Leases (Topic 842). The key difference between the existing standards and ASU 2016-02 is the requirement for lessees to recognize on their balance sheet all lease contracts with lease terms greater than 12 months, including operating leases. Specifically, lessees are required to recognize on the balance sheet at lease commencement, both (i) a right-of-use asset, representing the lessee’s right to use the leased asset over the term of the lease, and (ii) a lease liability, representing the lessee’s contractual obligation to make lease payments over the term of the lease. For lessees, ASU 2016-02 requires classification of leases as either operating or finance leases, which are similar to the current operating and capital lease classifications. However, the distinction between these two classifications under the ASU does not relate to balance sheet treatment, but relates to treatment and recognition in the statements of income and cash flows. Lessor accounting is largely unchanged from current US GAAP. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, for public entities. Early application is permitted. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

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Description of Business and Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Schedule of Accounts Payable

Accounts Payable—Accounts payable consisted of the following amounts as of March 31, 2017 and December 31, 2016:

(In thousands)	March 31, 2017		December 31, 2016
Trade payables	$	4,522	$	2,004
Revenue payable	11,101		11,296
Prepayments from partners	496		965
Miscellaneous payables	137		127
Total accounts payable	$	16,256	$	14,392

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Reconciliation of Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2017 is as follows (in thousands):

	March 31, 2017
Beginning balance at December 31, 2016	$	2,933
Liabilities incurred	35
Accretion expense	55
Ending balance at March 31, 2017	$	3,023
Current liability	$	—
Long term liability	$	3,023

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Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Components of Debt

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

	March 31, 2017				December 31, 2016
	Principal		Carrying Amount		Principal		Carrying Amount
Exit Credit Facility	$	16,651	$	16,651	$	16,651	$	16,651
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	42,559		32,481		41,170		30,554
Total debt	$	59,210	$	49,132	$	57,821	$	47,205

⁽¹⁾ The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes $2.6 million and $1.2 million of paid in-kind interest at March 31, 2017 and December 31, 2016, respectively. The carrying value includes $10.1 million and $10.6 million of unamortized debt discount at March 31, 2017 and December 31, 2016, respectively.

Schedule of Interest Expense and Effective Interest

The following table summarizes the total interest expense for the periods shown including contractual interest expense, amortization of debt discount, accretion and financing costs and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates).

	Successor				Predecessor
	March 31, 2017				March 31, 2016
	Interest Expense		Effective Interest Rate		Interest Expense		Effective Interest Rate
Successor Exit Credit Facility	$	252	6.1	%	$	—	—	%
13.50% Convertible Second Lien Senior Secured Notes due 2019 (1)	1,927		24.2	%	—		—	%
Predecessor Senior Credit Facility	—		—	%	870		7.2	%
8.0% Second Lien Senior Secured Notes due 2018 **	—		—	%	1,109		18.7	%
8.875% Senior Notes due 2019	—		—	%	2,688		9.1	%
3.25% Convertible Senior Notes due 2026	—		—	%	3		3.3	%
5.0% Convertible Senior Notes due 2029	—		—	%	84		5.0	%
5.0% Convertible Senior Notes due 2032	—		—	%	2,053		8.4	%
5.0% Convertible Exchange Senior Notes due 2032	—		—	%	1,484		*
Other	—		—	%	22		*
Total debt	$	2,179			$	8,313

(1) Interest expense for the period ended Mach 31, 2017 includes $0.5 million of debt discount amortization and $1.4 million of paid in-kind interest.

* - Not meaningful.

** - Includes $3.8 million gain from the change in fair value of the embedded derivative associated with the 8.0% Second Lien Notes.

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Net Loss Per Common Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Computation of Net Income (Loss) Per Common Share

The following table sets forth information related to the computations of basic and diluted loss per share.

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
	2017			2016
	(Amounts in thousands, except per share data)
Basic and Diluted loss per share:
Net loss applicable to common stock	$	(5,725	)	$	(19,737	)
Weighted average shares of common stock outstanding	9,109			74,521
Basic and Diluted loss per share (1) (2) (3) (4)	$	(0.63	)	$	(0.26	)
(1) Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid were not presented as they would have been anti-dilutive.	—			16,878
(2) Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Exchange Notes and 2032 Notes or interest paid were not presented as they would have been anti-dilutive.	—			5,910
(3) Common shares issuable on assumed conversion of restricted stock were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	288			13,949
(4) Common shares issuable on the 13.50% Convertible Second Lien Senior Secured Notes due 2019, associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.	5,664			—

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Commodity Derivative Activities (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Gains and Losses on Derivatives

The following table summarizes gains and losses we recognized on our oil and natural gas derivatives for the three months ended March 31, 2017 and 2016:

	Successor			Predecessor
	Three Months Ended March 31,			Three Months Ended March 31,
Oil and Natural Gas Derivatives (in thousands)	2017			2016
Gain on commodity derivatives not designated as hedges, settled	$	142		$	—
Gain (loss) on commodity derivatives not designated as hedges, not settled	(402		)	24
Total gain (loss) on commodity derivatives not designated as hedges	$	(260	)	$	24

Schedule of Price Risk Derivatives

As of March 31, 2017, the open positions on our outstanding commodity derivative contracts, all of which were natural gas contracts with BP, were as follows:

Contract Type	Daily Volume (MMBtu)	Total Volume (MMBtu)	Fixed Price		Fair Value at March 31, 2017 (In thousands)
Natural Gas Swaps
2017	6,000	1,470,000	$	3.20	$	(182	)
2018	12,000	4,380,000	$3.00 - $3.015		$	(79	)
Natural Gas Costless Collars
2017	12,000	3,300,000	$3.00 - $3.60		$	(141	)

Derivative Assets and Liabilities Recorded at Fair Value

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of March 31, 2017 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.

Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	—		$	—	$	—
Non-current Assets Commodity Derivatives	—		402			—		402
Current Liabilities Commodity Derivatives	—		(804		)	—		(804		)
Non-current Liabilities Commodity Derivatives	—		—			—		—
Total	$	—	$	(402	)	$	—	$	(402	)

Offsetting Assets

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 for the periods ending March 31, 2017 and December 31, 2016:

	March 31, 2017									December 31, 2016
Fair Value of Oil and Natural Gas Derivatives (in thousands)	Gross Amount			Amount Offset			As Presented			Gross Amount		Amount Offset		As Presented
Current Assets Commodity Derivatives	$	336		$	(336	)	$	—		$	—	$	—	$	—
Fair Value of Commodity Derivatives - Other Non-current Assets	413			(11		)	402			—		—		—
Fair Value of Commodity Derivatives - Current Liability	(1,140		)	336			(804		)	—		—		—
Non-current Liabilities Commodity Derivatives	(11		)	11			—			—		—		—
Total	$	(402	)	$	—		$	(402	)	$	—	$	—	$	—

Offsetting Liabilities

The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance Sheets for the periods ending March 31, 2017 and December 31, 2016:

	March 31, 2017									December 31, 2016
Fair Value of Oil and Natural Gas Derivatives (in thousands)	Gross Amount			Amount Offset			As Presented			Gross Amount		Amount Offset		As Presented
Current Assets Commodity Derivatives	$	336		$	(336	)	$	—		$	—	$	—	$	—
Fair Value of Commodity Derivatives - Other Non-current Assets	413			(11		)	402			—		—		—
Fair Value of Commodity Derivatives - Current Liability	(1,140		)	336			(804		)	—		—		—
Non-current Liabilities Commodity Derivatives	(11		)	11			—			—		—		—
Total	$	(402	)	$	—		$	(402	)	$	—	$	—	$	—

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Description of Business and Significant Accounting Policies - Schedule of Accounts Payable (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Trade payables	$ 4,522	$ 2,004
Revenue payable	11,101	11,296
Prepayments from partners	496	965
Miscellaneous payables	137	127
Total accounts payable	$ 16,256	$ 14,392

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Description of Business and Significant Accounting Policies - Narrative (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Description Of Company And Significant Accounting Policies [Line Items]
Full Cost Ceiling Test write-downs	$ 0
Asset impairment charges		$ 0
Minimum [Member]
Description Of Company And Significant Accounting Policies [Line Items]
Useful life	3 years
Maximum [Member]
Description Of Company And Significant Accounting Policies [Line Items]
Useful life	5 years

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Reconciliation of Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward [Roll Forward]
Beginning balance	$ 2,933
Liabilities incurred	35
Accretion expense	55
Ending balance	3,023
Current liability	0
Long term liability	$ 3,023	$ 2,933

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Debt - Components of Debt (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Principal	$ 59,210	$ 57,821
Carrying Amount	49,132	47,205
Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Principal	42,559	41,170
Carrying Amount	32,481	30,554
Paid-in kind interest	2,600	1,200
Unamortized discount	$ 10,100	$ 10,600

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Debt - Components of Debt, Interest Expense and Effective Interest Rate (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Oct. 12, 2016
13.50% Convertible Second Lien Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Stated interest rate	13.50%
8.0% Second Lien Senior Secured Notes due 2018 [Member]
Debt Instrument [Line Items]
Stated interest rate	8.00%
8.875% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Stated interest rate	8.875%
3.25% Convertible Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Stated interest rate	3.25%
5.0% Convertible Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
5.0% Convertible Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
5.0% Convertible Exchange Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
Successor [Member]
Debt Instrument [Line Items]
Interest Expense	$ 2,179
Gain on embedded derivative	0
Successor [Member] | Successor Exit Credit Facility [Member]
Debt Instrument [Line Items]
Interest Expense	$ 252
Effective Interest Rate	6.10%
Successor [Member] | 13.50% Convertible Second Lien Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 1,927
Effective Interest Rate	24.20%
Unamortized discount	$ 500
Paid-in kind interest	1,400
Stated interest rate			13.50%
Successor [Member] | Exit Credit Facility [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | 8.0% Second Lien Senior Secured Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Gain on embedded derivative	$ 3,800
Stated interest rate	8.00%
Successor [Member] | 8.875% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | 3.25% Convertible Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | 5.0% Convertible Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | 5.0% Convertible Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | 5.0% Convertible Exchange Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Successor [Member] | Other [Member]
Debt Instrument [Line Items]
Interest Expense	$ 0
Effective Interest Rate	0.00%
Predecessor [Member]
Debt Instrument [Line Items]
Interest Expense		$ 8,313
Gain on embedded derivative		3,845
Predecessor [Member] | Successor Exit Credit Facility [Member]
Debt Instrument [Line Items]
Interest Expense		$ 0
Effective Interest Rate		0.00%
Predecessor [Member] | 13.50% Convertible Second Lien Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 0
Effective Interest Rate		0.00%
Predecessor [Member] | Exit Credit Facility [Member]
Debt Instrument [Line Items]
Interest Expense		$ 870
Effective Interest Rate		7.20%
Predecessor [Member] | 8.0% Second Lien Senior Secured Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 1,109
Effective Interest Rate		18.70%
Predecessor [Member] | 8.875% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 2,688
Effective Interest Rate		9.10%
Predecessor [Member] | 3.25% Convertible Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 3
Effective Interest Rate		3.30%
Predecessor [Member] | 5.0% Convertible Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 84
Effective Interest Rate		5.00%
Predecessor [Member] | 5.0% Convertible Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 2,053
Effective Interest Rate		8.40%
Predecessor [Member] | 5.0% Convertible Exchange Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Interest Expense		$ 1,484
Predecessor [Member] | Other [Member]
Debt Instrument [Line Items]
Interest Expense		$ 22

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Debt - Narrative (Detail)			3 Months Ended
	Oct. 12, 2016 USD ($)	Oct. 12, 2016 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Debt [Line Items]
Principal			$ 59,210,000	$ 57,821,000
Carrying Amount			49,132,000	47,205,000
13.50% Convertible Second Lien Senior Secured Notes Due 2019 [Member]
Debt [Line Items]
Principal	$ 40,000,000.0	$ 40,000,000.0
Stated interest rate	13.50%	13.50%
Percentage of convertible note to common stock	15.00%
Cost less warrant issue to purchase common stock, period	10 years
Percentage of warrants issued for purchase of common stock, percentage	20.00%
Unamortized discount			10,100,000
Exit Credit Facility [Member]
Debt [Line Items]
Principal			16,651,000	16,651,000
Carrying Amount			$ 16,651,000	$ 16,651,000
8.0% Second Lien Senior Secured Notes due 2018 [Member]
Debt [Line Items]
Stated interest rate			8.00%
Successor [Member] | 13.50% Convertible Second Lien Senior Secured Notes Due 2019 [Member]
Debt [Line Items]
Total proved asset coverage ratio		1.10
Successor [Member] | 13.50% Convertible Second Lien Senior Secured Notes Due 2019 [Member] | After March 31, 2017 [Member]
Debt [Line Items]
Total proved asset coverage ratio		1.35
Successor [Member] | 13.50% Convertible Second Lien Senior Secured Notes Due 2019 [Member] | After September 30, 2017 [Member]
Debt [Line Items]
Total proved asset coverage ratio		1.50
Successor [Member] | Exit Credit Facility [Member]
Debt [Line Items]
Principal	$ 20,000,000	$ 20,000,000
Carrying Amount	20,000,000	20,000,000	$ 16,700,000
Outstanding balance and cash balance threshold for mandatory prepayments	27,500,000	27,500,000
Outstanding balance and cash balance threshold for mandatory prepayments, additional due to equity issuance	21,300,000	21,300,000
Outstanding balance and cash balance threshold for mandatory prepayments, reduction for equity issuance	2,500,000	2,500,000
Successor [Member] | Exit Credit Facility [Member] | On Or After April 1, 2018 [Member]
Debt [Line Items]
Outstanding balance and cash balance threshold for mandatory prepayments	7,500,000	7,500,000
Successor [Member] | 8.0% Second Lien Senior Secured Notes due 2018 [Member]
Debt [Line Items]
Stated interest rate			8.00%
Predecessor [Member] | 13.50% Convertible Second Lien Senior Secured Notes Due 2019 [Member]
Debt [Line Items]
Principal	40,000,000	40,000,000
Carrying Amount	29,000,000	29,000,000
Adjustments to additional paid in capital		11,000,000
Unamortized discount	$ 11,000,000	$ 11,000,000
Base Rate [Member] | Successor [Member] | Exit Credit Facility [Member]
Debt [Line Items]
Basis spread on variable rate			4.50%
London Interbank Offered Rate (LIBOR) [Member] | Successor [Member] | Exit Credit Facility [Member]
Debt [Line Items]
Basis spread on variable rate			5.50%
Effective percentage			6.53%
Exit Credit Facility [Member]
Debt [Line Items]
Minimum covenant proved assets coverage ratio	150.00%
Minimum secured debt asset overage ratio	110.00%
Exit Credit Facility [Member] | After December 31, 2018 [Member]
Debt [Line Items]
Minimum covenant proved assets coverage ratio	200.00%
Exit Credit Facility [Member] | After March 31, 2017 [Member]
Debt [Line Items]
Minimum secured debt asset overage ratio	135.00%
Exit Credit Facility [Member] | September 30, 2017 [Member]
Debt [Line Items]
Minimum secured debt asset overage ratio	150.00%
Maximum [Member] | Exit Credit Facility [Member] | Commencing With Fiscal Quarter Ending March 31, 2018 [Member]
Debt [Line Items]
Debt to income before taxes depreciation and amortization ratio	400.00%

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Net Loss Per Common Share - Computations of Basic and Diluted Income (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Successor [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Net loss applicable to common stock	$ (5,725)
Weighted average shares of common stock outstanding	9,109
Basic and Diluted loss per share (in dollars per share)	$ (0.63)
Successor [Member] | Assumed Conversion of Preferred Stock [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion	0
Successor [Member] | Assumed Conversion of Notes [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion	0
Successor [Member] | Assumed Conversion of Notes [Member] | Second Lien Term Loan [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion	5,664
Successor [Member] | Assumed Conversion of Restricted Stock, Stock Warrants and Employee Stock Options [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion	288
Predecessor [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Net loss applicable to common stock		$ (19,737)
Weighted average shares of common stock outstanding		74,521
Basic and Diluted loss per share (in dollars per share)		$ (0.26)
Predecessor [Member] | Assumed Conversion of Preferred Stock [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion		16,878
Predecessor [Member] | Assumed Conversion of Notes [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion		5,910
Predecessor [Member] | Assumed Conversion of Notes [Member] | Second Lien Term Loan [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion		0
Predecessor [Member] | Assumed Conversion of Restricted Stock, Stock Warrants and Employee Stock Options [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Common shares issuable upon assumed conversion		13,949

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Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax expense or benefit	$ 0
Unrecognized tax benefits	$ 0	$ 0

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Commodity Derivative Activities - Summary of Gains and Losses on Derivatives (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Successor [Member]
Derivative [Line Items]
Total gain (loss) on commodity derivatives not designated as hedges	$ (260)
Successor [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Gain on commodity derivatives not designated as hedges, settled	142
Gain (loss) on commodity derivatives not designated as hedges, not settled	(402)
Total gain (loss) on commodity derivatives not designated as hedges	$ (260)
Predecessor [Member]
Derivative [Line Items]
Total gain (loss) on commodity derivatives not designated as hedges		$ 24
Predecessor [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Gain on commodity derivatives not designated as hedges, settled		0
Gain (loss) on commodity derivatives not designated as hedges, not settled		24
Total gain (loss) on commodity derivatives not designated as hedges		$ 24

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Commodity Derivative Activities - Commodity Derivative Activities - Additional Information (Detail) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 0	$ 0

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Commodity Derivative Activities - Outstanding Commodity Derivative Contracts (Details) - Not Designated as Hedging Instrument [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($) MMBTU $ / MMBTU
2017 Natural Gas Calls [Member]
Derivative [Line Items]
Daily Volume (MMBtu)	6,000
Total Volume (MMBtu)	1,470,000
Fixed Price (in dollars per unit) | $ / MMBTU	3.20
Fair Value at March 31, 2017 | $	$ (182)
2018 Natural Gas Calls [Member]
Derivative [Line Items]
Daily Volume (MMBtu)	12,000
Total Volume (MMBtu)	4,380,000
Fair Value at March 31, 2017 | $	$ (79)
2018 Natural Gas Calls [Member] | Minimum [Member]
Derivative [Line Items]
Fixed Price (in dollars per unit) | $ / MMBTU	3.00
2018 Natural Gas Calls [Member] | Maximum [Member]
Derivative [Line Items]
Fixed Price (in dollars per unit) | $ / MMBTU	3.015
2017 Natural Gas Costless Collars [Member]
Derivative [Line Items]
Daily Volume (MMBtu)	12,000
Total Volume (MMBtu)	3,300,000
Fair Value at March 31, 2017 | $	$ (141)
2017 Natural Gas Costless Collars [Member] | Minimum [Member]
Derivative [Line Items]
Fixed Price (in dollars per unit) | $ / MMBTU	3.00
2017 Natural Gas Costless Collars [Member] | Maximum [Member]
Derivative [Line Items]
Fixed Price (in dollars per unit) | $ / MMBTU	3.60

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Commodity Derivative Activities - Reconciliation of Gross Amounts to Amounts as Presented on Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Current Liabilities Commodity Derivatives	$ (804)	$ 0
Predecessor [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current Assets Commodity Derivatives	0
Non-current Assets Commodity Derivatives	402
Current Liabilities Commodity Derivatives	(804)
Non-current Liabilities Commodity Derivatives	0
Total	(402)
Fair Value, Inputs, Level 2 [Member] | Predecessor [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current Assets Commodity Derivatives	0
Non-current Assets Commodity Derivatives	402
Current Liabilities Commodity Derivatives	(804)
Non-current Liabilities Commodity Derivatives	0
Total	(402)
Fair Value, Inputs, Level 3 [Member] | Predecessor [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current Assets Commodity Derivatives	0
Non-current Assets Commodity Derivatives	0
Current Liabilities Commodity Derivatives	0
Non-current Liabilities Commodity Derivatives	0
Total	0
Fair Value, Inputs, Level 1 [Member] | Predecessor [Member] | Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current Assets Commodity Derivatives	0
Non-current Assets Commodity Derivatives	0
Current Liabilities Commodity Derivatives	0
Non-current Liabilities Commodity Derivatives	0
Total	$ 0

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Commodity Derivative Activities - Derivative Table, Fair Value with Netting (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, As Presented	$ 0	$ 0
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Total Fair Value, Gross	(402,000)	0
Total Fair Value, Amount Offset	0	0
Total Fair Value, As Presented	(402,000)	0
Not Designated as Hedging Instrument [Member] | Current Assets [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Gross Amount	336,000	0
Derivative Asset, Amount Offset	(336,000)	0
Derivative Asset, As Presented	0	0
Not Designated as Hedging Instrument [Member] | Noncurrent Assets [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Gross Amount	413,000	0
Derivative Asset, Amount Offset	(11,000)	0
Derivative Asset, As Presented	402,000	0
Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Liability, Gross Amount	(1,140,000)	0
Derivative Liability, Amount Offset	336,000	0
Derivative Liability, As Presented	(804,000)	0
Not Designated as Hedging Instrument [Member] | Noncurrent Liabilities [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Liability, Gross Amount	(11,000)	0
Derivative Liability, Amount Offset	11,000	0
Derivative Liability, As Presented	$ 0	$ 0

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Commitments and Contingencies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 400,000	$ 400,000
Employer discretionary contribution amount	$ 0	$ 100,000