NOTE

1—Description

of Business and Summary of Significant Accounting Policies

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

Basis of Presentation

Principles of Consolidation

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

-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with US GAAP. The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior period financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

Use of Estimates

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

Cash and Cash Equivalents

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

ninety

days or less at date of purchase.

Accounts Payable

—Accounts payable consisted of the following items as of

December 31, 2019

and

2018

(in thousands):

	December 31,
	2019		2018
Trade payables	$	11,461	$	8,633
Revenue payables		14,483		16,665
Prepayments from partners		-		132
Other		404		304
Total Accounts payable	$	26,348	$	25,734

Accrued Liabilities

—Accrued liabilities consisted of the following items as of

December 31, 2019

and

2018

(in thousands):

	December 31,
	2019		2018
Accrued capital expenditures	$	6,175	$	8,086
Accrued lease operating expense		989		1,100
Accrued production and other taxes		430		338
Accrued transportation and gathering		2,258		1,888
Accrued performance bonus		4,642		3,420
Accrued interest		208		443
Accrued office lease		1,414		598
Accrued general and administrative expense and other		499		645
Total Accrued liabilities	$	16,615	$	16,518

Inventory

—Inventory consisted of equipm

ent, casing and tubulars tha

t 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 gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of o

il and 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 gas properties.

We have elected to adopt the Full Cost Method of Accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method of accounting better reflects the true economics of exploring for and

developing our oil and gas reserves.

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

not

include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impa

irment. 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 therefore subject to DD&A and the full cost ceiling test. For the years ended

December 31, 2019

and

December 31, 2018

, we transferred

$0.3

million and

$6.0

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

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

reserves.

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

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

three

five

years.

Full Cost Ceiling Test

—The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and 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 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 gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a

-month average pricing assumption.

The Full Cost Ceiling Test performed as of

December 31, 2019

and

December 31, 2018

resulted in

write-down of the oil and gas properties.

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

and

) 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

Inputs- unadjusted quoted market prices in active markets for identical assets or liabilities. We have

Level

instruments;

•

Level

Inputs- quotes that are derived principally from or corroborated by observable market data. Included in this Level are

our senior credit facilities 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

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

As of

December 31, 2019

and

December 31, 2018

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

Asset Retirement Obligations

—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and 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

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

in the fair value hierarchy.

Revenue Recognition

—Oil and natural gas revenues are generally recognized upon delivery of our produced oil and natural gas volumes to our customers. We record revenue in the m

onth our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales

may

not

be received for up to

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

We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. At

December

31,

2019

and

2018,

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

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

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

Note

Net Income or Net Loss Per Common Share

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

Note

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

Concentration of Credit Risk

—Due to the nature of the

industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers

for the years ended

December 31, 2019

and

2018

are as follows:

	Year Ended December 31,
	2019			2018
CIMA Energy, LP		39	%		41	%
Shell		19	%		0	%
ETC		19	%		15	%
CES		10	%		8	%
Genesis Crude Oil LP		8	%		13	%
Sunoco, Inc.		1	%		4	%
Williams Energy Resources LLC		0	%		1	%
Occidental Energy MA		0	%		1	%

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. See

Note

Guarantee

—As of

December 31, 2019

Goodrich Petroleum Company L

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

Notes (as defined below). The parent company has

independent assets or operations, the guarantee is full and unconditional, and the parent has

subsidiaries other than Goodrich Petroleum Company LLC.

Debt Issuance Cost

—The Company records debt issuance costs associated with its New

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

New Accounting Pronouncements

December

2019,

the Financia

l Accounting Standards Board (

“

FASB

”) issued Accounting Standards Update (“ASU”)

2019

12,

Income Taxes (Topic

740

): Simplifying the Accounting for Income Taxes. The amendments in this ASU adds new guidance to simplify accounting for income taxes, changes the accounting for certain income tax transactions and makes minor improvements to the codification. For public entities, the amendments in this ASU are effective for fiscal periods beginning after

December 15, 2020,

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

not

expect a material impact from the adoption of this ASU.

August 2018,

the FASB issued ASU

2018

13,

Fair Value Measurements (Topic

820

): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic

820

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

December 15, 2019,

including interim periods therein. We

do anticipate a material impact from the adoption of this ASU.