ABRAXAS PETROLEUM CORP - Quarter Report: 2020 September (Form 10-Q)

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC.

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our consolidated financial statements.

Forward-Looking Information

We make forward-looking statements throughout this report.  Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable.  The forward-looking information contained in this report is generally located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well.  These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends.  The factors that may affect our expectations regarding our operations include, among others, the following:

Initial production, or IP rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data become available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery (EUR), or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease-line offsets. Abraxas' standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.

GLOSSARY OF TERMS

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit.  Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

The following definitions apply to the technical terms used in this report.

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

“Boed or Boepd" – barrels of oil equivalent per day.

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

 Terms used to describe our interests in wells and acreage:

“Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

“Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting reserves.

“Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion.

“Exploratory well” is a well drilled to find and produce oil and or gas in an unproved area, to find a new reservoir in a field previously found to be producing in another reservoir, or to extend a known reservoir.

“Gross acres” are the number of acres in which we own a working interest.

“Gross well” is a well in which we own a working interest.

“Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres).

“Net well” is the sum of fractional ownership working interests in gross wells.

“Productive well” is an exploratory or a development well that is not a dry hole.

“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether such acreage contains proved reserves.

Terms used to assign a present value to or to classify our reserves:

“Developed oil and gas reserves*” Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)   Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Proved developed non-producing reserves*” are those quantities of oil and gas reserves that are developed behind pipe in an existing well bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved developed reserves*” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves*” Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” or “PUDs*” Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

“Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil and Gas Producing Activities.”

“Undeveloped oil and gas reserves*" Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition, see:http://www.ecfr.gov/cgibin/retrieveECFR?gp=1&SID=aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

Part I

FINANCIAL STATEMENTS

Item 1. Financial Statements

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our condensed consolidated financial statements. 

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(in thousands, except share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

1. Basis of Presentation

The accounting policies we follow as of January 1, 2020 are set forth in the notes to our audited consolidated financial statements in the Annual Report on Form 10-K for the year ended  December 31, 2019 filed with the SEC on June 26, 2020.  The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants. In the opinion of management, these statements reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations for the three and nine month periods ended September 30, 2020 and the statement of cash flows for the nine months ended September 30, 2020, are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019.

COVID-19

On January 30, 2020, the World Health Organization ("WHO”) announced a global health emergency because of a new strain of coronavirus ("COVID-19”) and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 as a pandemic, based on the rapid increase in exposure globally. In addition, in March 2020, members of OPEC failed to agree on production levels which is expected to cause an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market.

The price of both oil and gas has decreased primarily as a result of oil demand concerns due to the economic impacts of the COVID-19 virus and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. Declines in oil and natural gas prices affect the Company's liquidity, however the Company's commodity hedges partially protect its cash flows from such price declines. Additionally, if oil or natural gas prices remain depressed or continue to decline the Company will be required to record additional impairments to its oil and gas properties.

Consumer demand has decreased due to the spread of the COVID-19 outbreak and travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. The full impact of the coronavirus and the decrease in oil prices continue to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that they will have on the Company’s financial condition, liquidity and future results of operations. Management is actively monitoring the global situation and the impact or adverse effect on the Company’s results of future operations, financial position and liquidity in fiscal year 2020. Due to the recent oil price volatility, the Company has curtailed its 2020 capital spending program. The Company has also laid off selected employees, reduced officer salaries from 20% - 40% and reduced all other salaries from 5% - 20%. The Company has also eliminated substantially all overtime for field employees.  The Company began shutting in production in mid- March 2020 and began bringing wells back on production in mid- June 2020 as prices began to recover. As of September 30, 2020, a majority of such wells have been brought back on production.

In early March 2020, global oil and natural gas prices declined sharply, have since been volatile, and may decline again. The Company expects ongoing oil price volatility over the short term. Continued depressed oil prices have had and will continue to have a material adverse impact on the Company's oil revenue, which is mitigated somewhat by the Company's hedge contracts.

Reclassifications

Certain reclassifications have been made to the prior year financial statements to conform to the current period presentation.  These reclassifications were to share and per share data related to the 1 for 20 reverse stock split effective October 19, 2020. and had no effect on our previously reported results of operations.

Consolidation Principles

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC (“Raven Drilling”).

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which we or our affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Stock-Based Compensation, Option Plans and Warrants

Stock Options

We currently utilize a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.

The following table summarizes our stock-based compensation expense related to stock options for the periods presented: 

The following table summarizes our stock option activity for the nine months ended September 30, 2020, (in thousands):

As of September 30, 2020, there was approximately $0.07 million of unamortized compensation expense related to outstanding stock options that will be recognized from 2020 through 2022.

Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient of the award terminates employment with us prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

The following table summarizes our restricted stock activity for the nine months ended September 30, 2020: 

The following table summarizes our stock-based compensation expense related to restricted stock for the periods presented: 

As of   September 30, 2020, there was approximately $0.8 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized from 2020 through 2022.

Performance Based Restricted Stock

We issue performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in three years from the grant date upon the achievement of performance goals based on our Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of our TSR as compared to the peer group at the end of the three-year vesting period and can range from zero percent of the initial grant up to 200% of the initial grant.

The table below provides a summary of Performance Based Restricted Stock as of the date indicated:

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of our common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

 The following table summarizes our stock-based compensation expense related to performance based restricted stock for the periods presented: 

As of September 30, 2020, there was approximately $0.5 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 2020 through 2022.

Warrants for Common Stock

As of September 30, 2020, outstanding warrants to purchase shares of common stock were as follows:

In connection with the amended Second Lien Credit Agreement, on August 11, 2020, the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. As described in Note 2, on October 19, 2020 the Company effected a reverse stock split of the Company's authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share the warrant is  exercisable immediately, in whole or in part, on or before five years from the issuance date. The fair value of the warrant was recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and is being amortized over the loan term. 

Oil and Gas Properties

We follow the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with the acquisition of properties and successful and unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At September 30, 2020 our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves resulting in an impairment of $54.6 million and $136.1 million, for the three and nine months ended September 30, 2020.  At September 30, 2019, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.  We expect that we will have future impairments.

Restoration, Removal and Environmental Liabilities

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

We account for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements.

The following table summarizes our future site restoration obligation transactions for the nine months ended September 30, 2020 and the year ended December 31, 2019:

Recently Adopted Accounting Standards 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

Recently Issued Accounting Standards

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

2. Reverse Stock Split

On  October 19, 2020, the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock, $0.01 par value. The Company effected the reverse stock split pursuant to the Company’s filing of a Certificate of Change  with the Secretary of State of the State of Nevada on September 29, 2020. Under Nevada law, no amendment to the Company’s Articles of Incorporation was required in connection with the reverse stock split. The Company was authorized to issue 400,000,000 shares of common stock. As a result of the reverse stock split, the Company is authorized to issue 20,000,000 shares of common stock.  As a result of the reverse split, 168,069,305 outstanding shares of the Company’s common stock were exchanged for approximately 8,403,465 shares of the Company's common stock (subject to adjustment due to the effect of rounding fractional shares into whole shares). The reverse stock split will not have any effect on the stated par value of the common stock.   All per share amounts and number of shares in the condensed consolidated financial statements and related notes have been retroactively restated to reflect the reverse stock split, resulting in the transfer of $1.6 million from common stock to additional paid in capital at September 30, 2020 and December 31, 2019.

Additionally on October 19, 2020, all options, warrants and other convertible securities of the Company outstanding immediately prior to the reverse stock split will be adjusted by dividing the number of shares of common stock into which the options, warrants and other convertible securities are exercisable or convertible by 20, and multiplying the exercise or conversion price thereof by 20, all in accordance with the terms of the plans, agreements or arrangements governing such options, warrants and other convertible securities and subject to rounding to the nearest whole share.

The common stock began trading on a split-adjusted basis on the NASDAQ at the market open on October 19, 2020.  The trading symbol for the common stock remains "AXAS".

The reverse stock split was intended to bring the Company into compliance with the Nasdaq Stock Market Listing Rule 5550(a)(2) and the $1.00 per share minimum bid price requirement for continued listing on the NASDAQ.  On November 2, 2020, the Company received written notice from the NASDAQ that the Company has regained compliance with the Listing Rule 5550(a)(2) and the $1.00 per share minimum bid price requirement.

3. Revenue from Contracts with Customers

Revenue Recognition

Sales of oil, gas and natural gas liquids (“NGL”) are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. Our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. We believe that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

Oil sales

Our oil sales contracts are generally structured such that we sell our oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. We recognize revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser.

Gas and NGL Sales

Under our gas processing contracts, we deliver wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers, or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that we receive.

In these scenarios, we evaluate whether the midstream processing entity is the principal or the agent in the transaction. In our gas purchase contracts, we have concluded that the midstream processing entity is the agent, and thus, the midstream processing entity is our customer. Accordingly, we recognize revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

Disaggregation of Revenue

We are focused on the development of oil and natural gas properties primarily located in the following two operating regions in the United States: (i) the Permian/Delaware Basin and (ii) Rocky Mountain. We sold our remaining South Texas assets, which closed on November 1, 2019. Revenue attributable to each of those regions is disaggregated in the tables below.

Significant Judgments

Principal versus agent

We engage in various types of transactions in which midstream entities process our gas and subsequently market resulting NGL and residue gas to third-party customers on our behalf, such as our percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction price allocated to remaining performance obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC Topic 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under our product sales contracts, we are entitled to payment from purchasers once our performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. We record invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as we have satisfied our performance obligations through delivery of the relevant product. As a result, we have concluded that our product sales do not give rise to contract assets or liabilities under ASU 2014-09. At September 30, 2020 and December 31, 2019, our receivables from contracts with customers were $6.1 million and $17.0 million, respectively.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated.

We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2020, and 2019 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

4.  Income Taxes

Deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.

For the three and nine months ended September 30, 2020, and 2019, there was no income tax benefit due to net operating loss carryforwards ("NOLs") and we recorded a full valuation allowance against our net deferred tax asset. 

At December 31, 2019, we had, subject to the limitation discussed below, $245.2 million of pre-2018 NOLs and $64.7 million of post 2018 NOL carryforwards for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized. Any NOLs arising in 2018, 2019, and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of taxable income for tax years for 2020 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021 can generally be carried forward indefinitely and can offset up to 80% of future taxable income. The use of our NOLs will be limited if there is an "ownership change" in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of September 30, 2020, we have not had an ownership change as defined by Section 382.

Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards. Therefore, we established a valuation allowance of $76.2 million for deferred tax assets at  December 31, 2019 and of $67.4 million at September 30, 2020.

As of September 30, 2020, we did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2014 through 2019 remain open to examination by the tax jurisdictions to which we are subject.

The Coronavirus Aid, Relief, and Economic Security Act  that was enacted March 27, 2020 includes income tax provisions that allow NOLs to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions.  These provisions have no material impact on the Company.

5. Long-Term Debt

The following is a description of our debt as of September 30, 2020 and December 31, 2019 (in thousands):

First Lien Credit Facility

The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders.  As of September 30, 2020, $100.0 million was outstanding under the First Lien Credit Facility. 

Outstanding amounts under the First Lien Credit Facility accrues interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate  at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the federal funds rate plus 0.5%, and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. At September 30, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6%.

Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements.

Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of September 30, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves.

Under the amended First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility dated June 25, 2020 (the "1L Amendment") modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a $3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or before December 31, 2020, and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to $3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period ended  June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 31, 2020, respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from  March 31, 2021 through December 31, 2021 and $5.0 million thereafter; in all cases, general and administrative expense excludes up to $1.0 million in certain legal and professional fees; and (vi) permission for up to an additional $25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted to $102.0 million. The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company’s oil and gas properties.

As of September 30, 2020 we were in compliance with the financial covenants under the First Lien Credit Facility, as amended.

The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: 

The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 

Second Lien Credit Facility

On November 13, 2019, we entered into the Term Loan Credit Agreement, with Angelo Gordon Energy Servicer, LLC, as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility.  The Second Lien Credit facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. On November 13, 2019, $95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility.  As of September 30, 2020, the outstanding balance on the Second Lien Credit Facility was $118.3 million, which includes a $10.0 million exit fee. 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements, and, if such prepayment is made prior to  November 13, 2020, subject to payment of a Make Whole Amount, where applicable. “Make Whole Amount” is defined as, the sum of the interest payments (calculated on the basis of the interest rate as of the date of the relevant prepayment without discount) that would have accrued and been paid from the  date of prepayment to November 13, 2020 on the principal amount of such prepaid loans, whether such prepayments are optional, mandatory or as a result of acceleration.

Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of September 30, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

Under the amended Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility dated June 25, 2020 (the "2L Amendment") modified certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending between September 30, 2021 to December 31, 2021, and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved by Angelo Gordon Energy Servicer, LLC, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

 As of September 30, 2020 we were in compliance with the financial covenants under the Second Lien Credit Facility, as amended.

The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to:

The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

In connection with the amendment to the Second Lien Credit Facility on June 25, 2020, the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized on August 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020, the Company effected a reverse stock split of the Company’s authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share. The warrant is exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and are being amortized over the loan term. The Exit Fee shall be due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same.  The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized on August 11, 2020, resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of $4.1 million.

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and accrues interest in the amount of $35,672. The maturity date of the note is July 20, 2023. As of  September 30, 2020 and   December 31, 2019,  $2.9  million and $3.1 million, respectively, were outstanding on the note.

6. Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share:

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income per share is computed similar to basic; however diluted income per share reflects the assumed conversion of all potentially dilutive securities. For the three and nine month periods ended September 30, 2020 there was no dilutive potential shares relating to stock options and restricted stock due to our depressed stock price and losses in the periods. 

7.  Hedging Program and Derivatives

The derivative contracts we utilize are based on index prices that may and often differ from the actual oil and gas prices realized in our operations.  Our derivative contracts do not qualify for hedge accounting; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset.

The following table sets forth the summary position of our derivative contracts as of September 30, 2020:

The following table illustrates the impact of derivative contracts on our balance sheet:

8. Financial Instruments

Assets and liabilities measured at fair value are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. We are further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about our assets and liabilities measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value:

As of   September 30, 2020 and  December 31, 2019 our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under basis swaps, if the market price is above the fixed price, we pay the counter-party, if the market price is below the fixed price, the counter-party pays us. The NYMEX-based fixed price derivative swaps and basis differential swap contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these types of derivative contracts. As the fair value of NYMEX-based fixed price swaps are based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs into a model and compare our results to the third party for reasonableness. The fair value of the basis differential swap instruments are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3.

The following is additional information for our recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the nine months ended September 30, 2020.

Nonrecurring Fair Value Measurements

Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. Unproved oil and gas properties are assessed periodically, at least annually, to determine whether impairment has occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

9. Leases

Nature of Leases

We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

Real Estate Leases

We rent a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease is non-cancelable with a term of five years, expiring August 31, 2024. We have concluded our real estate agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

Field Equipment

We rent various field equipment from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one  year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days' notice. These leases are considered short term and  are not capitalized. We have a small number of  compressor leases that are longer than  twelve months. We have concluded that our equipment rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days' notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments.  Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the three and nine months ended September 30, 2020, the majority of which is included in lease operating expense, are as follows:

Supplemental balance sheet information related to our operating leases is included in the table below:
 

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows:

At September 30, 2020 we had only a lease on a residence and compressor equipment, with minimum lease payments with commitments that had initial or remaining lease terms in excess of one year. 

Supplemental cash flow information related to our operating leases is included in the table below:

10. Commitments and Contingencies

From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At September 30, 2020, we were not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial position or results of operations.

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

The following is a discussion and analysis of our financial condition, results of operations, liquidity and capital resources and should be read in conjunction with our consolidated financial statements and the notes thereto, included in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto as of and for the year ended December 31, 2019 and the related Management's Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on June 26, 2020. Please see "Forward Looking Information" above.

Except as otherwise noted, all tabular amounts are in thousands, except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2019, except for the adoption of Accounting Standards Update 2016-13, Financial Instruments - Credit Losses which was effective January 1, 2020. See "Recently Issued Accounting Standards" for more information.

General

We are an independent energy company primarily engaged in the acquisition, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development  of producing properties, principally through the development of shale or tight oil reservoirs in areas known to be productive of oil and gas utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling and stage fracturing. As a result of these activities, we believe that we have a number of development opportunities on our properties. 

COVID-19 Overview

In the first quarter of 2020, a new strain of coronavirus (“COVID-19”) emerged, creating a global health emergency that has been classified by the World Health Organization as a pandemic. As a result of the COVID-19 pandemic, consumer demand for both oil and gas has decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19. In addition, in March 2020, members of OPEC failed to agree on production levels, which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. OPEC agreed to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. As a result of this decrease in demand and increase in supply, the price of oil and gas has decreased, which has affected our liquidity. On one hand, the Company’s commodity hedges protect its cash flows from such price decline but, on the other hand, if oil or natural gas prices remain depressed or continue to decline the Company will be required to record oil and gas property write-downs.

In early March 2020, global oil and natural gas prices declined sharply, have since been volatile, and may decline again. The Company expects ongoing oil and gas price volatility over the short term. The full impact of the coronavirus and the decrease in oil prices continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that will have on the Company. Management is actively monitoring the global situation and the impact on the Company’s future operations, financial position and liquidity in fiscal year 2020. In response to the price volatility, the Company has taken action to reduce general and administrative costs, including  shutting in production in mid-March 2020, but subsequently started restoring production in mid-June, we have also suspended our capital expenditures indefinitely. As of September 30, 2020, a majority of such wells have been brought back on production.

Factors Affecting Our Financial Results

Our financial results depend upon many factors which significantly affect our results of operations including the following:

Commodity Prices and Hedging Arrangements.

The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. 

Oil and gas prices have been volatile and are expected to continue to be volatile.  As a result of the many uncertainties associated with the world political environment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL and gas prices in the future.  The market price of oil and condensate, NGL and gas in 2020 will impact the amount of cash generated from operating activities, which will in turn impact our financial position.

During the nine months ended September 30, 2020, the NYMEX future price for oil averaged $38.51 per Bbl as compared to $56.92 per Bbl in the same period of 2019. During the nine months ended September 30, 2020, the NYMEX future spot price for gas averaged $1.92 per MMBtu compared to $2.56 per MMBtu in the same period of 2019. Prices closed on nine months ended September 30, 2020 at $40.22 per Bbl of oil and $2.53 per MMBtu of gas, compared to closing on September 30, 2019 at $58.47 per Bbl of oil and $2.31 per MMBtu of gas.  On November 4, 2020 prices closed at$39.15 per Bbl of oil and $3.05 per MMBtu of gas.  If commodity prices decline, our revenue and cash flow from operations will also likely decline.  In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically.  If oil and gas prices decline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. The prices that we receive are also impacted by basis differentials, which can be significant, and are dependent on actual delivery points. Finally, low commodity prices will likely cause a reduction of our proved reserves.

The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to: 

The following table sets forth our average differentials for the nine month periods ended September 30, 2020 and 2019:

(1) Excludes the impact of derivative activities.

At September 30, 2020, our derivative contracts consisted of NYMEX-based fixed price swaps and NYMEX basis differential swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under basis differential swaps, we receive payment if the basis differential is greater than our swap price and pay when the differential is less than our swap price.

Our derivative contracts equate to approximately 101% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at September 30, 2020) from October 1 through December 31, 2020, 107% in 2021,  114%. in 2022, 85% in 2023 and 104%  in 2024 removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods.  However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow. We have in the past and will in the future sustain losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts. For the nine months ended September 30, 2020, we realized a gain of $53.2  million, consisting of a gain of $14.8 million on closed contracts and a gain of $38.4 million related to open contracts. For the nine months ended September 30, 2019, we realized a loss of $11.4 million consisting of a loss of $4.0 million on closed contracts and a loss of $7.4 million related to open contracts.  We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules. 

The following table sets forth our derivative contracts at September 30, 2020:

At September 30, 2020, the aggregate fair market value of our commodity derivative contracts was a net asset of approximately $33.4 million.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities.  Based on the reserve information set forth in our reserve report as of December 31, 2019, our average annual estimated decline rate for our net proved developed producing reserves is 41%; 19%; 15%; 12% and 11% in 2020, 2021, 2022, 2023 and 2024, respectively, 8% in the following five years, and approximately 8% thereafter.  These rates of decline are estimates and actual production declines could be materially different.  While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. In addition, the 1L Amendment limits capex to $3.0 million over any four consecutive quarters beginning with the quarter ended June 30, 2020. This limit is effective until the First Lien Credit Facility is paid down to $50.0 million, which will further limit our ability to replace production volumes.  The decline in oil prices that occurred in March 2020, due to COVID-19, has resulted in the suspension of  our 2020 drilling program as well as shutting in production for some period of time. Both of these measures will impact our production volumes going forward.

We had capital expenditures during the nine months ended September 30, 2020 of $6.1 million related to our exploration and development activities, net of changes in capital expenditures in accounts payable and changes in the asset retirement obligation balance.   Our capital expenditure budget for 2020 has been suspended indefinitely.  Management and the board of directors are also considering additional operating and overhead cost efficiencies that could be realized in connection with the 2020 budget. The amendments to our credit facilities, described in the "Liquidity and Capital Resources" section below, limit our capital expenditures to $3.0 million in any four consecutive quarters, beginning with the quarter ended June 30, 2020.  Our capital expenditures will not be able to offset oil and gas production decreases caused by natural field declines.

The following table presents historical net production volumes for the three and nine months ended September 30, 2020, and 2019:

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the three and nine months ended September 30, 2020, and 2019, by our major operating regions: