Table of Contents



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2020

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______

  

COMMISSION FILE NUMBER: 001-16071

  

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Nevada

 

74-2584033

(State of Incorporation)

 

(I.R.S. Employer Identification No.)

 

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

 

210-490-4788

(Registrant’s telephone number, including area code)

 

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

 

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

 

Title of each class Trading Symbol

Name of each exchange on which registered:

Common Stock, par value $.01 per share AXAS

The NASDAQ Stock Market, LLC

 

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

 

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

 

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

 

Large accelerated filer  ☐

Accelerated filer  ☒

Non-accelerated filer  ☐

Smaller reporting company  ☐

(Do not mark if a smaller reporting company)

Emerging growth company  ☐

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

 

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

 

The number of shares of the issuer’s common stock outstanding as of  June 30,  2020 was 168,069,305.

 

 

 
 

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.

 

Explanatory Note

 

On March 25, 2020, the U.S. Securities and Exchange Commission (the"SEC") issued an order under Section 36 of the Securities and Exchange Commission Modifying Exemptions From the Reporting and Proxy Delivery Requirements for Public Companies, (Release No. 34-88465) (the “Order”), which provides conditional relief to registrants subject to the reporting requirements of Section 13(a) of the Securities and Exchange Act of 1934 that are unable to meet a filing deadline due to circumstances related to the COVID-19 coronavirus. Due to the outbreak and spread of the COVID-19 coronavirus, the Company has experienced significant delays and disruptions in operations, communications, and access to personnel and professional advisors, resulting in limited support and insufficient time to prepare and complete this Quarterly Report. Accordingly, the Company filed a Current Report on Form 8-K on May 8, 2020 to indicate its intention to rely on the Order and take advantage of its relief by extending the deadline for filing this Form 10-Q by 45 days.  On June 24, 2020, the Company also filed a Notification of Late Filing on Form 12b-25 for similar reasons indicating that the Company would file this Form 10-Q no later than the fifth calendar day following the prescribed due date.

 

 

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:

 

 

the prices we receive for our production and the effectiveness of our hedging activities;

 

 

the availability of capital including under our credit facility;

 

 

our success in development, exploitation and exploration activities;

 

 

declines in our production of oil and gas;

 

 

our indebtedness and the significant amount of cash required to service our indebtedness;

     
  the proximity, capacity, cost and availability of pipelines and other transportation facilities; 

 

 

limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our bank credit facility and restrictive debt covenants;

 

 

our ability to make planned capital expenditures;

 

 

ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;

 

 

global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus (COVID-19);

 

 

political and economic conditions in oil producing countries, especially those in the Middle East;

 

 

price and availability of alternative fuels;

 

 

our ability to procure services and equipment for our drilling and completion activities;

 

 

our acquisition and divestiture activities;

 

 

weather conditions and events; and

 

 

other factors discussed elsewhere in this report.

 

 

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/cgi-bin/retrieveECFR?gp=1&SID=aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

 

 

 

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

 

 

PART I

 

 

 

 

ITEM 1 -

Financial Statements

 

 

Condensed Consolidated Balance Sheets - March 31, 2020 (unaudited) and December 31, 2019

6

 

Condensed Consolidated Statements of Operations – (unaudited) Three Months Ended March 31, 2020 and 2019

8

  Condensed Consolidated Statements of Stockholders' Equity (unaudited)  Three Months Ended March 31, 2020 and 2019

9

 

Condensed Consolidated Statements of Cash Flows – (unaudited) Three Months Ended March 31, 2020 and 2019

10

 

Notes to Condensed Consolidated Financial Statements - (unaudited)

11

 

 

 

ITEM 2 -

Management's Discussion and Analysis of Financial Condition and Results of Operations

24

 

 

 

ITEM 3 -

Quantitative and Qualitative Disclosures about Market Risk

35

 

 

 

ITEM 4 -

Controls and Procedures

35

 

 

 

 

PART II

OTHER INFORMATION

 

ITEM 1 -

Legal Proceedings

36

ITEM 1A -

Risk Factors

36

ITEM 2 -

Unregistered Sales of Equity Securities and Use of Proceeds

36

ITEM 3 -

Defaults Upon Senior Securities

36

ITEM 4 -

Mine Safety Disclosure

36

ITEM 5 -

Other Information

36

ITEM 6 -

Exhibits

36

 

Signatures

37

 

 

 

Part I

FINANCIAL STATEMENTS

 

 

Item 1. Financial Statements

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

   

March 31,

   

December 31,

 
   

2020

   

2019

 
   

(Unaudited)

         

Assets

               

Current assets:

               

Cash and cash equivalents

  $ -     $ -  

Accounts receivable:

               

Joint owners, net

    1,250       2,397  

Oil and gas production sales

    5,783       16,985  

Other

    4,499       263  

Total accounts receivable

    11,532       19,645  
                 

Derivative asset - short-term

    34,020       83  

Other current assets

    1,280       1,193  

Total current assets

    46,832       20,921  
                 

Property and equipment:

               

Proved oil and gas properties, full cost method

    1,166,720       1,162,094  

Other property and equipment

    39,304       39,295  

Total

    1,206,024       1,201,389  

Less accumulated depreciation, depletion, amortization and impairment

    (908,266 )     (872,431 )

Total property and equipment, net

    297,758       328,958  
                 

Operating lease right-of-use assets

    295       327  

Derivative asset - long-term

    36,788       4,170  

Other assets

    255       255  

Total assets

  $ 381,928     $ 354,631  

 

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)

 

   

March 31,

   

December 31,

 
   

2020

   

2019

 
   

(Unaudited)

         

Liabilities and Stockholders' Equity

               

Current liabilities:

               

Accounts payable

  $ 14,594     $ 19,280  

Joint interest oil and gas production payable

    8,097       18,050  

Accrued interest

    119       133  

Accrued insurance claim and other expenses

    5,355       361  

Operating lease liability - current

    88       98  

Derivative liability short-term

    800       10,688  

Current maturities of long-term debt

    284       280  
Other current liabilities     390       582  

Total current liabilities

    29,727       49,472  
                 

Long-term debt – less current maturities

    199,081       192,718  

Operating lease liabilities

    181       203  

Derivative liability long-term

          999  

Future site restoration

    7,447       7,420  

Total liabilities

    236,436       250,812  
                 

Commitments and contingencies (Note 9)

               
                 

Stockholders’ Equity:

               

Preferred stock, par value $0.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding

           

Common stock, par value $0.01 per share, authorized 400,000,000 shares; 168,069,305 and 168,361,061 issued and outstanding at March 31, 2020 and December 31, 2019, respectively

    1,681       1,684  

Additional paid-in capital

    420,373       420,140  

Accumulated deficit

    (276,562 )     (318,005 )

Total stockholders’ equity

    145,492       103,819  

Total liabilities and stockholders’ equity

  $ 381,928     $ 354,631  

 

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

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Revenues:

               

Oil and gas production revenues

               

Oil

  $ 15,535     $ 31,981  

Gas

    86       1,473  

Natural gas liquids

    97       1,056  

Other

    8       4  

Total revenue

    15,726       34,514  

Operating costs and expenses:

               

Lease operating

    5,286       7,734  

Production and ad valorem taxes

    1,537       3,098  

Rig expense

    299       672  

Depreciation, depletion, amortization and accretion

    9,279       13,574  
Proved property impairment     26,659       -  

General and administrative (including stock-based compensation of $230 and $373)

    2,447       2,728  

Total operating cost and expenses

    45,507       27,806  

Operating (loss) income

    (29,781 )     6,708  
                 

Other (income) expense:

               

Interest income

    (9 )     -  

Interest expense

    4,386       2,967  

Amortization of deferred financing fees

    129       121  

(Gain) 1oss on derivative contracts

    (75,730 )     29,075  

Total other (income) expense

    (71,224 )     32,163  

Income (loss) before income tax

    41,443       (25,455 )

Income tax (expense) benefit

           

Net income (loss)

  $ 41,443     $ (25,455 )
                 

Net income (loss) per common share - basic

  $ 0.24     $ (0.15 )

Net income (loss) per common share - diluted

  $ 0.24     $ (0.15 )
                 

Weighted average shares outstanding:

               

Basic

    169,723       166,041  

Diluted

    169,723       166,041  

 

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

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(in thousands, except share data)

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at December 31, 2019

    168,361,061     $ 1,684     $ 420,140     $ (318,005 )   $ 103,819  

Net income

    -       -       -       41,443       41,443  

Stock-based compensation

    -       -       230       -       230  
Restricted stock cancellations and forfeitures     (291,756 )     (3 )     3       -       -  

Balance at March 31, 2020

    168,069,305     $ 1,681     $ 420,373     $ (276,562 )   $ 145,492  

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at December 31, 2018

    166,713,784     $ 1,667     $ 417,844     $ (253,001 )   $ 166,510  

Net loss

    -       -       -       (25,455 )     (25,455 )

Stock-based compensation

    -       -       373       -       373  

Stock options exercised

    422,614       4       397       -       401  

Balance at March 31, 2019

    167,136,398     $ 1,671     $ 418,614     $ (278,456 )   $ 141,829  

 

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

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Operating Activities

               

Net income (loss)

  $ 41,443     $ (25,455 )

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

               

Net (gain) loss on derivative contracts

    (75,730 )     29,075  

Net cash settlements paid on derivative contracts

    1,713       (311 )

Depreciation, depletion and amortization

    9,176       13,463  
Proved property impairment     26,659        

Accretion of future site restoration

    103       111  

Amortization of deferred financing fees and issuance discount

    470       121  

Stock-based compensation

    230       373  
Settlement of asset retirement obligation           (386 )

Changes in operating assets and liabilities:

               

Accounts receivable

    8,113       10,110  

Other assets

    (3,502 )     84  

Accounts payable and accrued expenses

    (5,023 )     1,010  

Net cash provided by operating activities

    3,652       28,195  
                 

Investing Activities

               

Capital expenditures, including purchases and development of properties

    (9,549 )     (28,008 )

Proceeds from the sale of oil and gas properties

          992  

Net cash used in investing activities

    (9,549 )     (27,016 )
                 

Financing Activities

               

Proceeds from long-term borrowings

    8,000       3,000  

Payments on long-term borrowings

    (2,069 )     (4,066 )

Deferred financing fees

    (34 )     (56 )

Exercise of stock options

          401  

Net cash provided by (used in) financing activities

    5,897       (721 )
                 

Increase (decrease) in cash and cash equivalents

          458  

Cash and cash equivalents at beginning of period

          867  

Cash and cash equivalents at end of period

  $ -     $ 1,325  
                 

Supplemental disclosures of cash flow information:

               

Interest paid

  $ 4,050     $ 2,939  
                 

Non-cash investing and financing activities

               

Change in capital expenditures included in accounts payable

  $ (4,914 )   $ 1,822  

Change in asset retirement obligations

  $ -     $ 85  

 

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, and in the opinion of management, 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 and the cash flows for the three month period ended March 31, 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 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 oil and gas property write-downs.

 

Consumer demand has decreased since the spread of the COVID-19 outbreak and new 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 suspended 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 all overtime for field employees. Additionally, we have curtailed our capital expenditures. The Company began shutting in production in mid March 2020 and began bringing wells back on production in mid June 2020.

 

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 our hedge contracts.

 

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 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 and Option Plans

 

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: 

 

 

Three Months Ended

 

March 31,

 

2020

   

2019

 
$ 66     $ 151  

 

 

The following table summarizes our stock option activity for the three months ended March 31, 2020:

 

 

    Number of Shares     Weighted Average Option Exercise Price Per Share     Weighted Average Grant Date Fair Value Per Share  

Outstanding, December 31, 2019

    5,926     $ 2.47     $ 1.75  

Forfeited

    (315 )   $ 2.09     $ 1.53  

Outstanding, March 31, 2020

    5,611     $ 2.49     $ 1.76  

    

As of March 31, 2020, there was approximately $0.1 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 three months ended March 31, 2020

 

 

   

Number of Shares (thousands)

   

Weighted Average Grant Date Fair Value Per Share

 

Unvested, December 31, 2019

    1,781     $ 1.58  

Vested/Released

    (77 )   $ 1.59  

Forfeited

    (302 )   $ 1.58  

Unvested, March 31, 2020

    1,402     $ 1.58  

 

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

 

 

Three Months Ended

 

March 31,

 

2020

   

2019

 
$ 160     $ 143  

 

As of  March 31, 2020, there was approximately $1.3 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:

 

 

   

Number of Shares (thousands)

   

Weighted Average Grant Date Fair Value Per Share

 

Unvested, December 31, 2019

    1,154     $ 1.69  

Forfeited

    (188 )   $ 1.72  

Unvested, March 31, 2020

    966     $ 1.69  

 

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: 

 

 

Three Months Ended

 

March 31,

 

2020

   

2019

 
$ 4     $ 79  

 

As of March 31, 2020, there was approximately $0.9 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 2020 through 2022.

 

 

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 as well as 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 March 31, 2020  our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves resulting in an impairment of $26.7 million.  At March 31, 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 three months ended March 31, 2020 and the year ended December 31, 2019:

 

 

   

March 31, 2020

   

December 31, 2019

 

Beginning future site restoration obligation

  $ 7,420     $ 7,492  

New wells placed on production and other

    41       80  

Deletions related to property disposals

    -       (473 )
Deletions related to plugging costs     -       (890 )

Accretion expense

    103       436  

Revisions and other

    (117 )     775  

Ending future site restoration obligation

  $ 7,447     $ 7,420  

 

 

Recently Issued 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 analyses. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses 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.

 

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 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. ASU 2020-04 and its related amendments will be in effect through December 31, 2022. We are currently assessing the potential impact of ASU 2020-04 on our consolidated financial statements.

 

 

2. 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.

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 
   

Oil

   

Gas

   

NGL

   

Oil

   

Gas

   

NGL

 

Operating Regions:

                                               

Permian/Delaware Basin

  $ 8,507     $ 14     $ (2 )   $ 9,063     $ 287     $ 313  

Rocky Mountain

  $ 7,028     $ 72     $ 99     $ 21,800     $ 954     $ 740  

South Texas

  $ -     $ -     $ -     $ 1,118     $ 232     $ 3  

 

 

 

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 March 31, 2020 and December 31, 2019, our receivables from contracts with customers were $5.8 million and $16.9 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 months ended March 31, 2020, and 2019 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

 

3.  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 months ended March 31, 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 taxes. 

 

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 2017 NOL carryforwards for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized; and can offset 100% of future taxable income. As a result of recent tax legislation, any NOLs arising in 2018, 2019, and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 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 March 31, 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 March 31, 2020.

 

As of March 31, 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  ("CARES") that was enacted March 27, 2020 includes income tax provisions that allow NOL's 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.

 

 

 

 

4. Long-Term Debt

 

The following is a description of our debt as of March 31, 2020 and December 31, 2019, respectively:

 

   

March 31, 2020

   

December 31, 2019

 

First Lien Credit Facility

  $ 101,778     $ 95,778  
Second Lien Credit Facility     100,000       100,000  

Real estate lien note

    3,021       3,091  
      204,799       198,869  

Less current maturities

    (284 )     (280 )
      204,515       198,589  
Deferred financing fees, net     (5,434 )     (5,871 )
Total long-term debt, net of deferred financing fees   $ 199,081     $ 192,718  

 

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 March 31, 2020,  $102.0 million was outstanding under the First Lien Credit Facility. 

 

Prior to the amendments described in Note 10,  “Subsequent Events”, the First Lien Credit Facility had a maximum commitment of $200.0 million and availability is subject to a borrowing base. At March 31, 2020, the Company had a borrowing base of $135.0 million. The Company's borrowing base could never exceed the $200.0 million maximum commitment amount.  Outstanding amounts under the First Lien Credit Facility accrued 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 March 31, 2020, the interest rate on the First Lien Credit Facility was approximately 4.8%.

 

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 March 31, 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 First Lien Credit Facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements.  Prior to the amendments described in Note 10, "Subsequent Events", the Company was required to maintain a current ratio, as defined in the First Lien Credit Facility, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. Prior to the amendments described in Note 10, "Subsequent Events", the Company was also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 3.50 to 1.00. The current ratio was defined as the ratio of consolidated current assets to consolidated current liabilities.  The interest coverage ratio was defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. The total debt to EBITDAX ratio was defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date.  In connection with the November 13, 2019 amendment to the First Lien Credit Facility and prior to the amendments described in Note 10, Subsequent Events", a minimum asset coverage ratio was added to the covenants. The minimum asset coverage ratio was defined as the ratio of (a) the sum of (i) PV-9 of proven reserves classified as "developed" and "producing" and (ii) the PV-9 of proven reserves classified as "drilled uncompleted" (up to 20% of the sum (i) and (ii)  to (b) total debt. Prior to the amendments described in Note 10, "Subsequent Events", the Company was required as of the last day  of each fiscal quarter to maintain a minimum asset coverage ratio of not less than 1.45 to 1.00 (for the period between March 31, 2021 and December 31, 2021) and not less than 1.55 to 1.00 after December 31, 2021).

 

 

 

 

 

17

 

 

Table of Contents

 

As of March 31, 2020 we were in compliance with the financial covenants under the First Lien Credit Facility, with the exception of the asset coverage ratio. And, as noted previously, the Company failed to

(i) deliver the 2019 Audited Financials not later than 90 days after the end of such fiscal year (ii) file this Form 10-Q Quarterly Report for the period ended March 31, 2020 no later than 45 days after the end of such fiscal quarter and (iii) prevent existing hedge agreements from exceeding the maximum coverage permitted pursuant to the First Lien Credit Facility and (iv) failure to comply with the minimum Asset Coverage Ratio requirement with respect to the fiscal quarter ended March 31, 2020, which resulted in violations of certain covenants under the First Lien Credit Facility (as in effect prior to the First Lien Credit Facility Amendment (the "1L Amendment"), as defined in Note 10, "Subsequent Events"). Subject to the terms and conditions of the 1L Amendment, Société Générale and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults. 

 

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

 

 

incur or guarantee additional indebtedness;

 

transfer or sell assets;

 

create liens on assets;

 

pay dividends of make other distributions on capital stock or make other restricted payments;

 

engage in transactions with affiliates other than on an “arm’s length” basis;

 

make any change in the principal nature of our business; and

 

permit a change of control.

 

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 March 31, 2020, the outstanding balance on the Second Lien Credit Facility was $100.0 million. Prior to the amendments described in Note 10, "Subsequent Events",  outstanding amounts under the Second Lien Credit Facility accrues interest at a rate per annum equal (a)(i) for borrowings that we elect to accrue interest at the reference rate, the greater of (w) the reference rate utilized by Angelo Gordon Energy Servicer, LLC, (x) the federal funds rate plus 0.5%, (y) daily three-month LIBOR  and (z) 2.75%, plus, in each case 8.00%, (ii) for borrowings that we elect to accrue interest at the Eurodollar rate, the greater of (x) LIBOR and (y) 1.75%, plus, in each case, 9.0%, and (b) at any time an event of default exists, after as well as before judgment, 3% per annum plus the amount set forth above. At March 31, 2020, the interest rate on the Second Lien Credit Facility was approximately 10.9%. The Loans under the Second Lien Credit Facility were issued with an original issue discount of 3.50% of par.

 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the amendments described in Note 10 "Subsequent Events", 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 March 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's our proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

 

Under the Second Lien Credit Facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements. Prior to the amendments described in Note 10, "Subsequent Events" , the Company was  required to maintain a current ratio, as of the last day of each fiscal quarter, of not less than 1.00 to 1.00 and a total debt to consolidated EBITDAX ratio as of the last day of each fiscal quarter of  not more than 4.00 to 1.00. Prior to the amendments described in Note 10 " Subsequent Events" the Company was also are required as of the last day of each fiscal quarter to maintain a minimum asset coverage ratio of not less than 1.25 to 1.00 (for the period between December 31, 2019 and December 31, 2020), not less than 1.45 to 1.00 (for the period between March 31, 2021 and December 31, 2021), and not less than 1.55 to 1.00 (after December 31, 2021). The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. The total debt to consolidated EBITDAX ratio was defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. The minimum asset coverage ratio was defined as the ratio of (a) the sum of (i) PV-9 of proven reserves classified as “developed” and “producing” and (ii) the PV-9 of proven reserves classified as “drilled uncompleted” (up to 20% of the sum (i) and (ii))  to (b) total debt.

 

 As of March 31, 2020 we were in compliance with the financial covenants under the Second Lien Credit Facility, with the exception of the asset coverage ratio. And, as noted previously, the Company (i) failed to deliver the 2019 Audited Financials not later than 90 days after the end of such fiscal year, (ii) failed to file this Quarterly Report on Form 10-Q for the period ended March 31, 2020 no later than 60 days after the end of such fiscal quarter, which resulted in violations of certain covenants under the Second Lien Credit Facility (as in effect prior to the Second Lien Credit Facility Amendment (the "2L Amendment"), as defined in Note 10, "Subsequent Events"). Additionally, the Company failed to maintain the required hedges under the Second Lien Credit Facility with respect to the fiscal quarter ended March 31, 2020, which resulted in a violation of the Company’s covenant under the Second Lien Credit Facility (as in effect prior to the 2L Amendment). Subject to the terms and conditions of the Second Lien Credit Facility, Angelo Gordon Energy Servicer, LLC and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults.

 

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

 

 

incur or guarantee additional indebtedness;

 

transfer or sell assets;

 

create liens on assets;

 

 pay dividends or make other distributions on capital stock or make other restricted payments; 

 

engage in transactions with affiliates other than on an “arm’s length” basis;

 

make any change in the principal nature of our business; and

 

permit a change of control

 

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.

 

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  December 31, 2019, and March 31, 2020, $3.1 million and $3.0 million, respectively, were outstanding on the note.

 

 

 

 

 

5. Earnings per Share

 

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

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Numerator:

               

Net income

  $ 41,443     $ (25,455 )

Denominator:

               

Denominator for basic earnings per share – weighted-average common shares outstanding

    169,723       166,041  

Effect of dilutive securities:

               

Stock options and restricted shares

    -       -  

Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares

    169,723       166,041  
                 

Net income per common share - basic

  $ 0.24     $ (0.15 )
                 

Net income per common share - diluted

  $ 0.24     $ (0.15 )

 

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 month period ended March 31, 2019, 1,582 of potential shares relating to stock options, unvested restricted shares and unvested performance based restricted shares were excluded from the calculation of diluted income (loss) per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. For the three month period ended March 31, 2020 there was no dilutive potential shares relating to stock options and restricted stock due to our depressed stock price. 

 

 

6.  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 March 31, 2020:

 

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2020 April - December

    3,729     $ 55.10  

2021 January - December

    2,889     $ 57.62  

2022 January - December

    2,412     $ 50.60  

2023 January - December

    1,498     $ 50.60  

2024 January - December

    1,589     $ 50.60  
                 

Basis Swaps

               
2020 April - December     4,000     $ 2.98  
                 

 

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

 

Fair Value of Derivative Contracts as of March 31, 2020

 
   

Asset Derivatives

 

Liability Derivatives

 

Derivatives not designated as hedging instruments

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

 

Commodity price derivatives

 

Derivatives – current

  $ 34,020  

Derivatives – current

  $ 800  

Commodity price derivatives

 

Derivatives – long-term

    36,788  

Derivatives – long-term

    -  
        $ 70,808       $ 800  

 

 

Fair Value of Derivative Contracts as of December 31, 2019

 
   

Asset Derivatives

 

Liability Derivatives

 

Derivatives not designated as hedging instruments

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

 

Commodity price derivatives

 

Derivatives – current

  $ 83  

Derivatives – current

  $ 10,688  

Commodity price derivatives

 

Derivatives – long-term

    4,170  

Derivatives – long-term

    999  
        $ 4,253       $ 11,687  

 

 

 

7. 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:

 

 

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

 

Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

 

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 March 31, 2020 and December 31, 2019, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value:

 

    Quoted Prices in Active Markets for Identical Assets (Level 1)    

Significant Other Observable Inputs (Level 2)

   

Significant Unobservable Inputs (Level 3)

    Balance as of March 31, 2020  

Assets:

                               

NYMEX fixed price derivative contracts

  $     $ 69,533     $     $ 69,533  
NYMEX basis differential swap contracts                 1,275       1,275  

Total Assets

  $     $ 69,533     $ 1,275     $ 70,808  
                                 
Liabilities:                                

NYMEX fixed price derivative contracts

  $     $     $     $ -  

NYMEX basis differential swaps

                800       800  

Total Liabilities

  $     $ -     $ 800     $ 800  

 

    Quoted Prices in Active Markets for Identical Assets (Level 1)     Significant Other Observable Inputs (Level 2)    

Significant Unobservable Inputs (Level 3)

    Balance as of December 31, 2019  

Assets:

                               

NYMEX fixed price derivative contracts

  $     $ 4,253     $     $ 4,253  

Total Assets

  $     $ 4,253     $     $ 4,253  
                                 

Liabilities:

                               

NYMEX fixed price derivative contracts

  $     $ 5,583     $     $ 5,583  

NYMEX basis differential swaps

                6,104       6,104  

Total Liabilities

  $     $ 5,583     $ 6,104     $ 11,687  

 

As of  March 31, 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 three months ended March 31, 2020.

 

Unobservable inputs at January 1, 2020

  $ (6,104 )

Changes in market value

    5,178  

Settlements during the period

    1,401  

Unobservable inputs at March 31, 2020

  $ 475  

 

 

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.

 

 

8. 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. 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 months ended March 31, 2020, the majority of which is included in lease operating expense, are as follows:

 

   

Three Months Ended March 31, 2020

 

Operating lease cost

  $ 37  

Short-term lease expense (1)

  $ 594  

Total lease expense

  $ 631  
         

Short-term lease costs (2)

  $ 973  

 

 

(1)

Short-term lease expense represents expense related to leases with a contract term of 12 months or less.

  (2) These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

 

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

   

March 31, 2020

 

Operating lease ROU assets

  $ 295  

Operating lease liability - current

  $ 88  

Operating lease liabilities - long-term

  $ 181  

 

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

 

    March 31, 2020  

Weighted Average Remaining Lease Term (in years)

    9.32  

Weighted Average Discount Rate

    6 %

 

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

 

   

Operating Leases

 

Remainder of 2020

  $ 102  

2021

    51  

2022

    46  

2023

    40  

2024

    19  

Thereafter

    102  

Total lease payments

    360  

Less imputed interest

    (91 )

Total lease liability

  $ 269  

 

At March 31, 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:

 

   

Three Months Ended March 31, 2020

 

Cash paid for amounts included in the measurement of lease liabilities

  $ -  

ROU assets added in exchange for lease obligations (since adoption)

  $ -  

 

 

 

9. 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 March 31, 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.

 

 

10. Subsequent Events

 

Paycheck Protection Program Loan

 

On May 4, 2020, the Company entered into a an unsecured loan with the U.S. Small Business Administration ("SBA") in the amount of $1.4 million under the Paycheck Protection Program (the "PPP Loan") with an interest rate of 1.0% and maturity date two years from the effective date of the PPP Laon. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act") and is administered by the SBA.  Payments are required to be made in seventeen monthly installments of principal and interest, with the first payment being due on the date that is seven months after the date of the PPP loan. Under the CARES Act, the PPP Loan is eligible for forgiveness for the portion of the PPP Loan proceeds used for payroll costs and other designated operating expenses for up to eight weeks, provided at least 75% of PPP Loan proceeds are used for payroll costs and the Company meets all necessary criteria for forgiveness. Receipt of these funds requires the Company to, in good faith, certify that the PPP Loan was necessary to support ongoing operations of the Company during the economic uncertainty created by the COVID-19 pandemic. This certification further requires the Company to take into account current business activity and the ability to access other sources of liquidity sufficient to support ongoing operations in a manner that is not significantly detrimental to the business. Additionally, the SBA provides no assurance that the Company will obtain forgiveness of the PPP Loan in whole or in part.

 

Amendments to First Lien Credit Facility and Second Lien Credit Facility

 

Waiver and Amendment No. 10 to Third Amended and Restated Agreement 
 

         

 On June 25, 2020, the Company and its subsidiary guarantors entered into the Waiver and Amendment No. 10 to Credit Agreement (the “1L Amendment”) with Société Générale, as administrative agent and  lender, and the lenders party thereto, pursuant to which the parties agreed to, among other things, (i) waive the Company’s events of default with respect to its First Lien Credit Facility as a result of the Borrower’s failure to (A) deliver audited financial statements for the fiscal year ended December 31, 2019 not later than 90 days after the end of such fiscal year in violation of the First Lien Credit Facility and the Second Lien Credit Facility, (B) deliver a consolidated unaudited balance sheet and unaudited financial statements for the fiscal quarter ended March 31, 2020 not later than 45 days after the end of such fiscal quarter in violation of the First Lien Credit Facility and not later than 60 days after the end of such fiscal quarter in violation of the Second Lien Credit Facility and (C) prevent existing hedge agreements from exceeding the maximum coverage permitted pursuant to the  First Lien Credit Facility and (D) failure to comply with the minimum Asset Coverage Ratio requirement with respect to the fiscal quarter ended March 31, 2020 coverage permitted pursuant to the  First Lien Credit Facility and (ii) amend certain covenants and payment provisions of the First Lien Credit Facility.  
 
          Due to the unprecedented conditions surrounding the outbreak and spread of the COVID-19 pandemic, the recent decline in oil prices, and related geopolitical developments, the Company failed to (i) file its Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, (ii) file this Quarterly Report on Form 10-Q for the period ended March 31, 2020 no later than 45 days after the end of such fiscal quarter and (iii) prevent existing hedge agreements from exceeding the maximum coverage permitted pursuant to the First Lien Credit Facility,  which resulted in violations of certain covenants under the First Lien Credit Facility (as in effect prior to the 1L Amendment). Subject to the terms and conditions of the 1L Amendment, Société Générale and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults. 
 
       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 ending June 30, 2020, $8.25 million for the four fiscal quarter period ending 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 from $135.0 million 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.

 

Waiver and Second Amendment to Term Loan Credit Agreement   

 
         On June 25, 2020, the Company and its subsidiary guarantors entered into the Waiver and Second Amendment to Term Loan Credit Agreement (the “2L Amendment”) with Angelo Gordon Energy Servicer, LLC, as administrative agent and issuing lender, and the lenders party there to, pursuant to which the parties agreed to, among other things, waive the Company’s designated events of default with respect to its Second Lien Credit Facility and amend certain covenants and payment provisions of the Second Lien Credit Facility. 
 
        As noted previously, the Company failed to file its Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under the Second Lien Credit Facility (as in effect prior to the 2L Amendment). Additionally, the Company failed to maintain the hedges required to be maintained pursuant to the Second Lien Credit Facility with respect to the fiscal quarter ended March 31, 2020, which resulted in a violation of the Company’s covenant under the Second Lien Credit Facility (as in effect prior to the 2L Amendment) to maintain certain required hedges. An additional Event of Default has occurred as a result of the Borrower’s failure to comply with the minimum Asset Coverage Ratio requirement with respect to the fiscal quarter ended March 31, 2020.  Subject to the terms and conditions of the Second Lien Credit Facility, Angelo Gordon Energy Servicer, LLC and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults. 
 
       The 2L Amendment modifies 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 ending June 30, 2020, $8.25 million for the four fiscal quarter period ending September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

 

Fee Letter

 
       On June 25, 2020, the Company, in connection with the 2L Amendment and to induce Angelo Gordon Energy Servicer, LLC and the lenders to enter into the 2L Amendment, entered into the Fee Letter (the “Fee Letter”) with Angelo Gordon Energy Servicer, LLC, pursuant to which the Company will (i) pay $10.0 million exit fee to Angelo Gordon Energy Servicer, LLC and the lenders upon maturity of the obligations under the Second Lien Credit Facility or the earlier acceleration or payment in full; (ii) grant warrants having an exercise price of $0.01 in an amount equal to 19.9% of the fully diluted common equity of the Company to Angelo Gordon Energy Servicer, LLC and the lenders; (iii) negotiate and provide an alternative financial arrangement that would afford Angelo Gordon Energy Servicer, LLC and the lenders an economic benefit equivalent in value to the warrants if the warrants cannot be issued on terms satisfactory to Angelo Gordon Energy Servicer, LLC; and (iv) protect the lenders by taking such reasonable steps as necessary to grant the lenders either (a) the right to appoint one member to the Company’s Board of Directors or (b) Board observation rights reasonably satisfactory to the administrative agent.

 

Future compliance with the covenants under the First Lien Credit Facility and Second Lien Credit Facility is reliant upon the Company's ability to successfully implement cost reductions, control capital expenditures and restart production that has been shut in. In the event of a future covenant violation, the Company would attempt to obtain waivers or amendments of the related agreements; however, it is uncertain if such waivers or amendments could be obtained on acceptable terms or at all.  In the event we default under the First Lien Credit Facility or Second Lien Credit Facility, amounts outstanding would become due and payable at the option of the lenders. 

 

 

 

 

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 there to 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 the 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, we began shutting in production in Mid March 2020 and have subsequently started restoring production in mid June and into the third quarter., we have also suspended our capital expenditures indefinitely.

 

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 the effectiveness of our hedging arrangements;

 

 

the level of total sales volumes of oil and gas;

 

 

the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;

 

 

the level of and interest rates on borrowings; and

 

 

the level and success of exploration and development activity.

 

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 three months ended March 31, 2020, the NYMEX future price for oil averaged $46.29 per Bbl as compared to $54.91 per Bbl in the same period of 2019. During the three months ended March 31, 2020, the NYMEX future spot price for gas averaged $1.87 per MMBtu compared to $2.87 per MMBtu in the same period of 2019. Prices closed on three months ended March 31, 2020 at $20.48 per Bbl of oil and $1.64 per MMBtu of gas, compared to closing on March 31, 2019 at $60.14 per Bbl of oil and $2.66 per MMBtu of gas.  On June 22, 2020 prices closed at $40.73 per Bbl of oil and $1.66 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: 

 

 

basis differentials which are dependent on actual delivery location;

 

 

adjustments for BTU content;

 

 

quality of the hydrocarbons; and

 

 

gathering, processing and transportation costs.

 

The following table sets forth our average differentials for the three months ended March 31, 2020, and 2019:

 

   

Oil - NYMEX

   

Gas - NYMEX

 
   

2020

   

2019

   

2020

   

2019

 

Average realized price (1)

  $ 41.82     $ 49.00     $ 0.11     $ 1.28  

Average NYMEX price

    46.29       54.91       1.87       2.87  

Differential

  $ (4.47 )   $ (5.91 )   $ (1.76 )   $ (1.59 )

                                                                                

(1) Excludes the impact of derivative activities.

 

At March 31, 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 124% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at March 31, 2020) from April 1 through December 31, 2020, 91% in 2021,  97%. in 2022, 73% in 2023 and 89%  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 three months ended March 31, 2020, we realized a gain of $75.7  million, consisting of a gain of $2.5 million on closed contracts and a gain of $73.2 million related to open contracts. For the three months ended March 31, 2019, we realized a loss of $29.1 million consisting of a loss of $1.0 million on closed contracts and a loss of $28.1 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 March 31, 2020:

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2020 April - December

    3,729     $ 55.10  

2021 January - December

    2,889     $ 57.62  

2022 January - December

    2,412     $ 50.60  

2023 January - December

    1,498     $ 50.60  

2024 January - December

    1,589     $ 50.60  
                 

Basis Swaps

               
2020 April - December     4,000     $ 2.98  
                 

 

At March 31, 2020, the aggregate fair market value of our commodity derivative contracts was a net asset of approximately $70.0 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 for the next 12 months, 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 three months ended March 31, 2020 of $4.6 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 operating and overhead cost efficiencies that could be realized in connection with the 2020 capital budget. The amendments to our credit faclities 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 months ended March 31, 2020, and 2019:

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Total production (MBoe)

    617       979  

Average daily production (Boepd)

    6,776       10,874  

% Oil

    60 %     67 %

 

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 months ended March 31, 2020, and 2019, by our major operating regions:

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Oil production (MBbls)

               

Rocky Mountain

    179       444  

Permian/Delaware Basin

    192       189  

South Texas

    -       20  

Total

    371       653  

Gas production (MMcf)

               

Rocky Mountain

    499       604  

Permian/Delaware Basin

    245       452  

South Texas

    -       95  

Total

    744       1,151  

NGL production (MBbls)

               

Rocky Mountain

    90       98  

Permian/Delaware Basin

    31       36  

South Texas

    -       -  

Total

    121       134  

Total production (MBoe) (1)

    617       979  

Average sales price per Bbl of oil (2)

               

Rocky Mountain

  $ 39.20     $ 49.06  

Permian/Delaware Basin

    44.26       48.01  

South Texas

    -       56.99  

Composite

    41.82       49.00  

Average sales price per Mcf of gas (2)

               

Rocky Mountain

  $ 0.14     $ 1.58  

Permian/Delaware Basin

    0.06       0.64  

South Texas

    -       2.44  

Composite

    0.11       1.28  

Average sales price per Bbl of NGL

               

Rocky Mountain

  $ 1.10     $ 7.59  

Permian/Delaware Basin

    0.06       8.60  

South Texas

    -       15.42  

Composite

    0.80       7.87  

Average sales price per Boe (2)

  $ 25.49     $ 35.26  

Average cost of production per Boe produced (3)

               

Rocky Mountain

  $ 6.06     $ 3.92  

Permian/Delaware Basin

    12.42       15.81  

South Texas

    9       14.80  

Composite

    6.29       7.96  

 

 

(1)

Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.

 

(2)

Before the impact of hedging activities.

 

(3)

Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

 

 

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any asset sales or financing on terms acceptable to us, if at all.  As of March 31, 2020, our borrowing base was $135.0 million with $33.0 million of availability under our credit facility. Our credit facilities were amended in June 2020 as described in Note 10 to the unaudited condensed consolidated financial statements included in this Quarterly Report. The borrowing base under our First Lien Credit Facility was reduced to the then outstanding balance of $102.0 million, resulting in no additional availability, additionally, any excess cash, as defined in the First Lien Credit Facility, will be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance. As a result, with the exception of $3.0 million of funds available for working capital purposes, we expect to have limited available capital.

 

 

Borrowings and Interest.  At March 31, 2020, we had a total of $102.0 million outstanding under our First Lien Credit Facility, $100.0 million under our Second Lien Credit facility and total indebtedness of $204.8 million (including the current portion). If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements, although as noted above, under the terms of the 2L Amendment, interest under the 2nd Lien Notes is now paid-in-kind.  

 

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2019, we operated properties accounting for approximately 96% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. However, the amendments to our First Lien Credit Facility and Second Lien Credit facility, as described in Note 10 to our unaudited condensed consolidated financial statements place severe restrictions on our future capital expenditures and we have suspended any planned drilling activity for 2020 indefinitely.

 

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that we will have any significant exploration and development activities in the near term or that they will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations will decline.  Approximately 28% of our estimated proved reserves on a Boe basis at March 31, 2020 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We will be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition are expected to be adversely affected.

 

 

 

 

 

Results of Operations

 

Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 

Operating revenue (1):

               

Oil sales

  $ 15,535     $ 31,981  

Gas sales

    86       1,473  

NGL sales

    97       1,056  

Other

    8       4  

Total operating revenues

  $ 15,726     $ 34,514  

Operating (loss) income

  $ (29,781 )   $ 6,708  

Oil sales (MBbls)

    371       653  

Gas sales (MMcf)

    744       1,151  

NGL sales (MBbls)

    121       134  

Oil equivalents (MBoe)

    617       979  

Average oil sales price (per Bbl)(1)

  $ 41.82     $ 49.00  

Average gas sales price (per Mcf)(1)

  $ 0.11     $ 1.28  

Average NGL sales price (per Bbl)

  $ 0.80     $ 7.87  

Average oil equivalent sales price (Boe) (1)

  $ 25.49     $ 35.26  

___________________

 

(1)

Revenue and average sales prices are before the impact of hedging activities.

 

Comparison of Three Months Ended March 31, 2020 to Three Months Ended March 31, 2019

 

Operating Revenue. During the three months ended March 31, 2020, operating revenue decreased to $15.7 million from $34.5 million for the same period of 2019. The decrease in revenue was primarily due to lower commodity prices as well as lower sales volumes during the three months ended March 31, 2020 as compared to the same period of 2019. Lower realized commodity prices for all products had a negative impact of $5.0 million on operating revenue,  lower sales volumes for all products negatively impacted revenue by  $13.9 million for the three months ended March 31, 2020

 

Oil sales volumes decreased to 371 MBbl during the three months ended March 31, 2020 from 653 MBbl for the same period of 2019. The decrease in oil sales volume was primarily due to wells being shut in for frac protect, natural field declines and property sales, offset by new wells brought on line since the first quarter of 2019. New wells brought on line since the first quarter of 2019 contributed 114 MBbl for the three months ended March 31, 2020. Gas sales volumes decreased to 744 MMcf for the three months ended March 31, 2020 from 1,151 MMcf for the same period of 2019. The decrease in gas production was primarily due to field declines and continued pipeline constraints in West Texas and North Dakota, additionally, we have shut in a number of dry gas wells in west Texas due to negative gas prices, partially offset by new wells brought on line since the first quarter of 2019 which contributed 147 MMcf for the three months ended March 31, 2020. NGL sales volumes decreased to 121 MBbl for the three months ended March 31, 2020 from 134 MBbl for the same period of 2019. The decrease in NGL sales was primarily due to decreased gas volumes.

 

Lease Operating Expenses (“LOE”). LOE for the three months ended March 31, 2020 decreased to $5.3 million from $7.7 million for the same period in 2019. The decrease in LOE was primarily due to the disposition of our south Texas properties during the fourth quarter of 2019, and lower non-recurring  LOE in 2020 as compared to 2019. LOE per Boe for the three months ended March 31, 2020 was $8.57 compared to $7.90 for the same period of 2019. The increase per Boe was due to primarily to lower sales volumes, offset by lower total costs for the three months ended March 31, 2020 as compared to the same period of 2019.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended March 31, 2020 decreased to $1.5  million from $3.1 million for the same period of 2019.  Production and ad valorem taxes for the three months ended March 31, 2020 were 10% of total oil, gas and NGL sales as compared to 9% for the same period of 2019. The increase in the percentage of revenue is due to more revenue coming from North Dakota which has a higher tax rate.

 

 

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, was decreased to $2.2 million for the three months ended March 31, 2020 as compared to $2.4 in 2019. G&A expense per Boe, excluding stock-based compensation, was $3.60 for the quarter ended March 31, 2020 compared to $2.41 for the same period of 2019. The increase per Boe was primarily due to  lower sales volumes.

 

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of our common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended March 31, 2020, stock-based compensation expense was $0.2 million compared to $0.4 million for the same period of 2019. The decrease was primarily due to the cancellation, forfeiture of restricted stock and performance based restricted stock.

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, excluding accretion of future site development, for the three months ended March 31, 2020  decreased to $9.2 million from $13.5 million for the same period of 2019. The decrease was primarily due to lower future development cost included in the March 31, 2020 internal reserve report, as well as lower production volumes during the three months ended March 31, 2020 as compared to the same period of 2019.  DD&A expense per Boe for the three months ended March 31, 2020 was $14.88 compared to $13.76 in 2019. The increase in DD&A expense per Boe was primarily due to a lower full cost pool as the result of the impairment incurred as of December 31, 2019. 

 

Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, 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. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of March 31, 2020 our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves, resulting in the recognition of an impairment of  $26.7  million. As of  March 31, 2019, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

 

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. The continued decline in commodity prices since March 31, 2020, due to COVID-19, will result in our proved reserves being revised downward, requiring  further write-down of the carrying value of our oil and gas properties during the remainder of 2020.

 

Interest Expense. Interest expense for the three months ended March 31, 2020 increased to $4.4 million compared to $3.0 million for the same period of 2019. The increase in interest expense in 2020 was due to higher levels of debt during the three months ended March 31, 2020 as compared to the same period in 2019, as well as higher overall interest rates in 2020 as compared to 2019. For the three months ended March 31, 2020 the interest rate on our first lien credit facility averaged 4.7% as compared to 5.9%  for the same period of 2019. For the three months ended March 31, 2020 the interest rate on our second lien credit facility averaged  10.8%. We anticipate higher interest rates and increased interest expense in the future as a result of the amendments to our credit facilities.

 

Loss (Gain) on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of March 31, 2020, and March 31, 2019. The net estimated value of our commodity derivative contracts was a net asset of approximately $70.0 million as of March 31, 2020. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended March 31, 2020, we recognized a gain on our commodity derivative contracts of $75.7 million, consisting of a gain on closed contracts of  $2.5 million and a gain of $73.2 million related to open contracts. For the three months ended March 31, 2019, we recognized a loss on our commodity derivative contracts of $29.1 million, consisting of a loss of $1.0 million on closed contracts and a loss of $28.1 million related to open contracts.

 

Income Tax Expense. For the three months ended March 31, 2020 and March 31, 2019 there was no income tax expense recognized due to our NOL carryforwards. The CARES Act, that was enacted March 27, 2020 includes income tax provisions that allow net operating losses (NOL's) 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 did not have a material impact on the Company.

 

 

 

Liquidity and Capital Resources

 

General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following:

 

 

the development and exploration of existing properties, including drilling and completion costs of wells;

 

•  

acquisition of interests in additional oil and gas properties; and

 

production and transportation facilities.

 

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties. In January 2019, we announced that we had engaged Petrie Partners to assist us in identifying and assessing our options for our Bakken properties. In October 2019 we announced that we had broadened the engagement of Petrie Partners to include a more thorough review of our business and strategic plans, competitive positioning and potential alternative transactions that might further enhance shareholder value. Petrie’s expanded mandate to assess options for Abraxas is a broad one, which might include sales of assets, merger or acquisition transactions, additional financing alternatives or other strategic transactions.  Due to the drastic decrease in oil prices that began in early March 2020  as a result of  the OPEC price war and the COVID-19 pandemic, we have suspended capital expenditures for 2020. Subsequently further negotiations in April 2020 between members of OPEC and Russia led to an agreement to reduce production volumes in an effort to stabilize global oil prices. While prices have recovered from the lows in March 2020, they remain at depressed levels.  If oil prices remain at depressed levels  we will incur additional impairments in 2020, which could include writing off our proved undeveloped reserves.

 

Our principal sources of capital are cash flows from operations, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to sell properties or complete any financings on terms acceptable to us, if at all. We believe that our cash flow from these sources going forward, will be adequate to fund our operations. In June 2020, the borrowing base on our First Lien Credit Facility was reduced to the then outstanding balance of $102.0 million, with no further availability. Additionally, any excess cash, as defined in the First Lien Credit Facility, will be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance. We have shut in production in mid March resulting in future cash flows being driven by hedge settlements, and our ability to successfully implement cost reductions and restart production, which began in mid June 2020 and will continue in the third quarter of 2020.

 

 

Working Capital (Deficit). At March 31, 2020, our current assets $46.8  million exceeded our current liabilities of  $29.7 million resulting in a working capital surplus of $17.1 million. This compares to a working capital deficit of $28.6 million at December 31, 2019. Current assets as of March 31, 2020 primarily consisted of accounts receivable of $11.5 million, current amount of our derivative asset of  $34.0 million and other current assets of $1.3 million. Current liabilities at March 31, 2020 primarily consisted of trade payables of $14.6 million, revenues due third parties of $8.1 million, current maturities of long-term debt of $0.3 million, the current amount of our derivative liability of $0.8 million and accrued expenses and other of $5.6 million. 

 

Capital Expenditures. Capital expenditures for the three months ended March 31, 2020, and 2019 were $4.6 million and $30.0 million, respectively.

 

The table below sets forth the components of these capital expenditures:

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 
   

(In thousands)

 

Expenditure category:

               

Exploration/Development

  $ 4,625     $ 29,935  

Acquisitions

    -       -  

Facilities and other

    10       40  

Total

  $ 4,635     $ 29,975  

 

During the three months ended March 31, 2020 and 2019 our capital expenditures were primarily for development of our existing properties.  Cash basis capital expenditures for the three months ended March 31, 2020 of $9.5 million includes $4.9 million for a decrease in capital expenditures in accounts payable, resulting in net accrual basis capital expenditures of $4.6 million. As described in Note 10 to the unaudited condensed consolidated financial statements included in this Quarterly Report, our amended credit facilities limit capital expenditures to $3.0 million for any four consecutive quarters beginning with the quarter ending June 30, 2020.  Based on our  capital expenditure limits,  the Company will not be able to offset oil and gas production decreases caused by natural field declines.

 

 

Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: 

 

 

   

Three Months Ended March 31,

 
   

2020

   

2019

 
   

(In thousands)

 

Net cash provided by operating activities

  $ 3,652     $ 28,195  

Net cash used in investing activities

    (9,549 )     (27,016 )

Net cash provided by (used in) financing activities

    5,897       (721 )

Total

  $ -     $ 458  

 

Operating activities for the three months ended March 31, 2020 provided  $3.7 million in cash compared to providing $28.2 million in the same period of 2019.  Higher net income offset by higher unrealized gains on derivatives and changes in operating assets and liabilities accounted for most of these funds. Investing activities used $9.5 million during the three months ended March 31, 2020 primarily for the development of our existing properties, investing activities also included a reduction in accounts payable related to capital expenditures of $4.9 million. In