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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 June 30, 2019

 

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 August 6, 2019 was 168,452,060.

 

 

 

 

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; and

 

 

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;

 

 

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 becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery, or 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.

 

2

 

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 shall 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.

 

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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=7aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

 

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ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

 

 

PART I

 

 

 

 

ITEM 1 -

Financial Statements

6

 

Condensed Consolidated Balance Sheets - June 30, 2019 (unaudited) and December 31, 2018

6

 

Condensed Consolidated Statements of Operations – (unaudited) Three and Six Months Ended June 30, 2019 and 2018

8

  Condensed Consolidated Statements of Stockholders' Equity (unaudited)  Three and Six Months Ended June 30, 2019 and 2018

9

 

Condensed Consolidated Statements of Cash Flows – (unaudited) Six Months Ended June 30, 2019 and 2018

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

 

5

 

 

Part I

FINANCIAL STATEMENTS

 

 

Item 1. Financial Statements

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

   

June 30,

   

December 31,

 
   

2019

   

2018

 
   

(Unaudited)

         

Assets

               

Current assets:

               

Cash and cash equivalents

  $ -     $ 867  

Accounts receivable:

               

Joint owners, net

    12,522       17,110  

Oil and gas production sales

    17,023       21,991  

Other

    1,114       535  

Total accounts receivable

    30,659       39,636  
                 

Derivative asset - short-term

    517       9,602  

Other current assets

    781       626  

Total current assets

    31,957       50,731  
                 

Property and equipment:

               

Proved oil and gas properties, full cost method

    1,135,758       1,091,905  

Other property and equipment

    39,548       39,453  

Total

    1,175,306       1,131,358  

Less accumulated depreciation, depletion, amortization and impairment

    (794,056 )     (768,140 )

Total property and equipment, net

    381,250       363,218  
                 

Operating lease right-of-use assets

    518       -  

Deferred financing fees, net

    964       1,149  

Derivative asset - long-term

    4,394       10,527  

Other assets

    265       265  

Total assets

  $ 419,348     $ 425,890  

 

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

 

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

 

 

   

June 30,

   

December 31,

 
   

2019

   

2018

 
   

(Unaudited)

         

Liabilities and Stockholders' Equity

               

Current liabilities:

               

Accounts payable

  $ 41,092     $ 39,571  

Joint interest oil and gas production payable

    17,052       23,063  

Accrued interest

    312       335  

Other accrued expenses

    1,047       511  

Operating lease liability - current

    284        

Derivative liability short-term

    7,785       616  

Current maturities of long-term debt

    274       267  

Total current liabilities

    67,846       64,363  
                 

Long-term debt – less current maturities

    185,953       183,091  

Operating lease liabilities

    229        

Derivative liability long-term

    3,529       4,434  

Future site restoration

    7,763       7,492  

Total liabilities

    265,320       259,380  
                 

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; 168,452,060 and 166,713,784 issued and outstanding at June 30, 2019 and December 31, 2018, respectively

    1,684       1,667  

Additional paid-in capital

    419,122       417,844  

Accumulated deficit

    (266,778 )     (253,001 )

Total stockholders’ equity

    154,028       166,510  

Total liabilities and stockholders’ equity

  $ 419,348     $ 425,890  

 

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

 

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

 

 

   

Three Months Ended June 30,

   

Six Months Ended June 30,

 
   

2019

   

2018

   

2019

   

2018

 

Revenues:

                               

Oil and gas production revenues

                               

Oil

  $ 34,146     $ 27,472     $ 66,127     $ 63,466  

Gas

    408       1,608       1,881       3,985  

Natural gas liquids

    265       1,835       1,321       4,058  

Other

    1       1       5       37  

Total revenue

    34,820       30,916       69,334       71,546  

Operating costs and expenses:

                               

Lease operating

    8,066       5,730       15,800       10,299  

Production and ad valorem taxes

    2,926       2,485       6,024       5,598  

Rig expense

    -       -       672       -  

Depreciation, depletion, amortization and accretion

    12,188       8,839       25,762       19,099  

General and administrative (including stock-based compensation of $521; $879; $894 and $1,466, respectively)

    2,705       3,065       5,433       5,793  

Total operating cost and expenses

    25,885       20,119       53,691       40,789  

Operating income

    8,935       10,797       15,643       30,757  
                                 

Other (income) expense:

                               

Interest expense

    2,765       1,492       5,732       2,691  

Amortization of deferred financing fees

    128       111       249       207  

(Gain) 1oss on derivative contracts

    (5,636 )     19,763       23,439       27,646  

Gain on sale of non-oil and gas assets

    -       (15 )     -       (12 )

Total other (income) expense

    (2,743 )     21,351       29,420       30,532  

Income (loss) before income tax

    11,678       (10,554 )     (13,777 )     225  

Income tax (expense) benefit

                       

Net income (loss)

  $ 11,678     $ (10,554 )   $ (13,777 )   $ 225  
                                 

Net income (loss) per common share - basic

  $ 0.07     $ (0.06 )   $ (0.08 )   $ 0.00  

Net income (loss) per common share - diluted

  $ 0.07     $ (0.06 )   $ (0.08 )   $ 0.00  
                                 

Weighted average shares outstanding:

                               

Basic

    166,491       165,162       165,727       164,812  

Diluted

    167,349       165,162       165,727       167,715  

 

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

 

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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 March 31, 2019

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

Net income

    -       -       -       11,678       11,678  

Stock-based compensation

    -       -       521       -       521  
Stock options exercised     755       -       -       -       -  

Restricted stock issued, net of forfeitures

    1,314,907       13       (13 )     -       -  

Balance at June 30, 2019

    168,452,060     $ 1,684     $ 419,122     $ (266,778 )   $ 154,028  

 

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at March 31, 2018

    165,881,694     $ 1,659     $ 416,068     $ (300,043 )   $ 117,684  

Net loss

    -       -       -       (10,554 )     (10,554 )

Stock-based compensation

    -       -       879       -       879  

Stock options exercised

    133,335       1       4       -       5  

Restricted stock issued, net of forfeitures

    696,181       7       (7 )     -       -  

Balance at June 30, 2018

    166,711,210     $ 1,667     $ 416,944     $ (310,597 )   $ 108,014  

 

 

                   

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

    -       -       -       (13,777 )     (13,777 )

Stock-based compensation

    -       -       894       -       894  

Stock options exercised

    423,369       4       397       -       401  
Restricted stock issued, net of forfeitures     1,314,907       13       (13 )     -       -  

Balance at June 30, 2019

    168,452,060     $ 1,684     $ 419,122     $ (266,778 )   $ 154,028  

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at December 31, 2017

    165,889,901     $ 1,659     $ 415,471     $ (310,822 )   $ 106,308  

Net income

    -       -       -       225       225  

Stock-based compensation

    -       -       1,466       -       1,466  

Stock options exercised

    145,253       2       14       -       16  

Restricted stock issued, net of forfeitures

    676,056       6       (7 )     -       (1 )

Balance at June 30, 2018

    166,711,210     $ 1,667     $ 416,944     $ (310,597 )   $ 108,014  

 

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

 

9

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

 

   

Six Months Ended June 30,

 
   

2019

   

2018

 

Operating Activities

               

Net (loss) income

  $ (13,777 )   $ 225  

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

               

Loss on sale of non-oil and gas assets

    -       (12 )

Net loss on derivative contracts

    23,439       27,646  

Net cash settlements (paid) received on derivative contracts

    (1,957 )     (9,847 )

Depreciation, depletion, amortization and accretion

    25,762       19,099  

Amortization of deferred financing fees

    249       207  

Stock-based compensation

    894       1,466  

Settlement of asset retirement obligation

    (386 )      

Changes in operating assets and liabilities:

               

Accounts receivable

    8,977       (631 )

Other assets

    (444 )     1,381  

Accounts payable and accrued expenses

    (58 )     5,752  

Net cash provided by operating activities

    42,699       45,286  
                 

Investing Activities

               

Capital expenditures, including purchases and development of properties

    (63,577 )     (73,818 )

Proceeds from the sale of oil and gas properties

    16,805       82  

Proceeds from the sale of non-oil and gas assets

    -       27  

Net cash used in investing activities

    (46,772 )     (73,709 )
                 

Financing Activities

               

Proceeds from long-term borrowings

    23,000       35,000  

Payments on long-term borrowings

    (20,131 )     (7,129 )

Deferred financing fees

    (64 )     (199 )

Exercise of stock options

    401       15  

Net cash provided by financing activities

    3,206       27,687  
                 

Decrease in cash and cash equivalents

    (867 )     (736 )

Cash and cash equivalents at beginning of period

    867       1,618  

Cash and cash equivalents at end of period

  $ -     $ 882  
                 

Supplemental disclosures of cash flow information:

               

Interest paid

  $ 5,778     $ 2,577  
                 

Non-cash investing and financing activities

               

Change in capital expenditures included in accounts payable (decrease) increase

  $ (3,248 )   $ 2,267  

Change in asset retirement obligations

  $ 51     $ 36  

 

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

 

10

Table of Contents

 

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 followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on March 15, 2019. Such policies have been continued without change, except as noted herein, due to the change in lease accounting adopted in the current period. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. 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 and six month periods ended June 30, 2019 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

 

Reclassifications

 

Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations.

 

Consolidation Principles

 

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

 

Rig Accounting

 

In accordance with SEC Regulation S-X, no income is  recognized in connection with contractual drilling services performed in connection with properties in which the Company or its 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.

 

 

Recently Adopted Lease Accounting Standard

 

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use (“ROU”) asset and lease liability for certain leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.

 

The new standard was effective for us in the first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized an ROU asset (or operating lease right-of-use asset) and a lease liability with no retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to:

 

 

Not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less);

 

Not reassess whether a contract contains a lease, lease classification and initial direct costs; and

 

Not reassess certain land easements in existence prior to January 1, 2019.

 

The impact of adoption of this new standard on our balance sheet was as follows:

 

   

January 1, 2019

 

Operating lease ROU asset

  $ 687  

Operating lease liability - current

  $ (108 )

Operating lease liability - long-term

  $ (579 )

 

Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update. For more information, see Note 8.

 

11

 

Stock-Based Compensation and Option Plans

 

Stock Options

 

The Company currently utilizes 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 the Company’s stock-based compensation expense related to stock options for the periods presented: 

 

 

Three Months Ended

   

Six Months Ended

 

June 30,

   

June 30,

 

2019

   

2018

   

2019

   

2018

 
$ 74     $ 574     $ 225     $ 914  

 

The following table summarizes the Company’s stock option activity for the six months ended June 30, 2019:

 

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

Outstanding, December 31, 2018

    7,549     $ 2.37     $ 1.68  

Granted

                 

Exercised

    (469 )   $ 0.98     $ 0.68  

Forfeited

    (572 )   $ 3.00     $ 2.12  

Outstanding, June 30, 2019

    6,508     $ 2.41     $ 1.71  

    

As of June 30, 2019, there was approximately $0.3 million of unamortized compensation expense related to outstanding stock options that will be recognized from 2019 through 2022.

 

12

 

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 the Company 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 the Company’s restricted stock activity for the six months ended June 30, 2019

 

 

   

Number of Shares (thousands)

   

Weighted Average Grant Date Fair Value Per Share

 

Unvested, December 31, 2018

    827     $ 2.15  

Granted

    1,315     $ 1.34  

Vested/Released

    (228 )   $ 2.22  

Forfeited

        $ -  

Unvested, June 30, 2019

    1,914     $ 1.59  

 

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

 

 

Three Months Ended

   

Six Months Ended

 

June 30,

   

June 30,

 

2019

   

2018

   

2019

   

2018

 
$ 277     $ 221     $ 420     $ 468  

 

As of June 30, 2019, there was approximately $2.5 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized from 2019 through 2022.

 

Performance Based Restricted Stock

 

The Company issues 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 the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of the Company’s 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, 2018

    405     $ 2.37  

Granted

    803     $ 1.34  

Vested/Released

        $ -  

Forfeited

        $ -  

Unvested, June 30, 2019

    1,208     $ 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 the Company's 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.

 

13

 

 

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

 

 

Three Months Ended

   

Six Months Ended

 

June 30,

   

June 30,

 

2019

   

2018

   

2019

   

2018

 
$ 170     $ 84     $ 249     $ 84  

 

As of June 30, 2019, there was approximately $1.6 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 2019 through 2022.

 

Oil and Gas Properties

 

The Company follows 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At June 30, 2019 and 2018, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

 

In May 2019, the Company closed on the sale of its non-operated assets in the Bakken. Proceeds from the sale of approximately $15.8 million were used to reduce outstanding indebtedness under its credit facility. In accordance with full cost accounting rules, the sale was not deemed to be singnificant,; therefore, no gain or loss was recorded and the proceeds were credited to the full cost pool.

 

14

 

Restoration, Removal and Environmental Liabilities

 

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company 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.

 

The Company accounts 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 the Company’s future site restoration obligation transactions for the six months ended June 30, 2019 and the year ended December 31, 2018

 

 

   

June 30, 2019

   

December 31, 2018

 

Beginning future site restoration obligation

  $ 7,492     $ 8,775  

New wells placed on production and other

    80       612  

Deletions related to property disposals and plugging costs

    (487 )     (2,270 )

Accretion expense

    220       516  

Revisions and other

    458       (141 )

Ending future site restoration obligation

  $ 7,763     $ 7,492  

 

 

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. The Company's 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. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

 

Oil sales

 

The Company's oil sales contracts are generally structured such that it sells its 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. The Company recognizes 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 the Company's gas processing contracts, it delivers 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 the Company 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 the Company receives.

 

In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

 

Imbalances

 

The Company utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at June 30, 2019 and 2018.

 

Disaggregation of Revenue

 

The Company is focused on the development of oil and natural gas properties primarily located in the following three operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the tables below.

 

 

   

Three Months Ended June 30,

 
   

2019

   

2018

 
   

Oil

   

Gas

   

NGL

   

Oil

   

Gas

   

NGL

 

Operating Regions:

                                               

Permian/Delaware Basin

  $ 15,562     $ 24     $ 27     $ 9,664     $ 609     $ 613  

Rocky Mountain

  $ 17,567     $ 208     $ 238     $ 15,479     $ 674     $ 1,180  

South Texas

  $ 1,017     $ 176     $ -     $ 2,329     $ 325     $ 42  

 

   

Six Months Ended June 30,

 
   

2019

   

2018

 
   

Oil

   

Gas

   

NGL

   

Oil

   

Gas

   

NGL

 

Operating Regions:

                                               

Permian/Delaware Basin

  $ 24,626     $ 311     $ 340     $ 24,039     $ 1,528     $ 1,411  

Rocky Mountain

  $ 39,367     $ 1,162     $ 978     $ 34,719     $ 1,802     $ 2,583  

South Texas

  $ 2,134     $ 408     $ 3     $ 4,708     $ 655     $ 64  

 

15

 

Significant Judgments

 

Principal versus agent

 

The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf, such as the Company's 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 the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company 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, the Company has utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is 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 the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records 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 the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASU 2014-09. At June 30, 2019 and December 31, 2018, our receivables from contracts with customers were $17.0 million and $22.0 million, respectively.

 

Prior-period performance obligations

 

The Company records 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, the Company is 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.

 

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

16

 

 

3.  Income Taxes

 

The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.

 

For the three and six months ended June 30, 2019 and 2018, there was no income tax benefit due to net operating loss carryforwards ("NOLs") and the Company recorded a full valuation allowance against its net deferred taxes. 

 

At December 31, 2018, the Company had, subject to the limitation discussed below, $245.2 million of pre-2018 NOLs and $46.8 million of 2018 NOL carryforwards for U.S. tax purposes.  The Company's pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising after January 1, 2018 can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes. Effective January 1, 2018 the alternative minimum tax no longer applies to corporations.

 

The use of the Company's NOLs will be limited if there is an "ownership change" in its 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 June 30, 2019, the Company has not had an ownership change as defined by Section 382. Given historical losses, uncertainties exist as to the future utilization of the NOL. Therefore, the Company established a valuation allowance of $67.3 million for deferred tax assets at December 31, 2018

 

As of June 30, 2019, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2013 through 2018 remain open to examination by the tax jurisdictions to which the Company is subject.

 

Tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1), was enacted on December 22, 2017. ASC 740, Accounting for Income Taxes, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017. Since the Company's federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to 21% did not materially affect the Company's financial statements. Significant provisions  may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, a limitation on utilization of NOLs generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of NOLs generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, the Company does not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of its NOL carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from the Company's  current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection.

 

 

4. Long-Term Debt

 

The following is a description of the Company’s debt as of June 30, 2019 and December 31, 2018, respectively:

 

 

   

June 30, 2019

   

December 31, 2018

 

Senior secured credit facility

  $ 183,000     $ 180,000  

Real estate lien note

    3,227       3,358  
      186,227       183,358  

Less current maturities

    (274 )     (267 )
    $ 185,953     $ 183,091  

 

 

Credit Facility

 

The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility.  As of June 30, 2019$183.0  million was outstanding under the credit facility.

 

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At June 30, 2019, the Company had a borrowing base of $217.5 million. The borrowing base is determined semi-annually by the lenders based upon the Company's reserve reports, one of which must be prepared by its independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Company's proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and the Company is able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or the Company must pledge additional oil and gas properties or other assets as collateral. The Company does not currently have any substantial unpledged assets and it may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause the Company to fail to be in compliance with the financial covenants described below. The Company's borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of its then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. The Company's borrowing base can never exceed the $300.0 million maximum commitment amount.  Outstanding amounts under the credit facility bear interest (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, 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) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or (ii) if we elect, LIBOR plus, in each case, 2.5%-3.5% depending on the utilization of the borrowing base. At June 30, 2019, the interest rate on the credit facility was approximately 5.7% assuming LIBOR borrowings.

 

17

 

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the credit facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

 

Each of the Company's subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. The Company has also granted our lenders a security interest in our headquarters building.

 

Under the credit facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements.  The Company is required to maintain a current ratio, as defined in the 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.  The Company is 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 is defined as the ratio of consolidated current assets to consolidated current liabilities.  For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20.  The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date.  For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the headquarters building and obligations with respect to surety bonds and derivative contracts.

 

At June 30, 2019, the Company was in compliance with all of these financial covenants. As of June 30, 2019, the interest coverage ratio was 8.12 to 1.00, the total debt to EBITDAX ratio was 2.24 to 1.00, and our current ratio was 1.10 to 1.00.

 

The 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;

 

 

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 credit facility also contains certain additional covenants including requirements that:

 

 

100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and

 

 

if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility.

 

The 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. As of June 30, 2019, the Company was in compliance with all of the terms of the credit facility.

 

18

 

Real Estate Lien Note

 

The Company has 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 note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of June 30, 2019 and December 31, 2018, $3.2 million and $3.4 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 June 30,

   

Six Months Ended June 30,

 
   

2019

   

2018

   

2019

   

2018

 

Numerator:

                               

Net income (loss)

  $ 11,678     $ (10,554 )   $ (13,777 )   $ 225  

Denominator:

                               

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

    166,491       165,162       165,727       164,812  

Effect of dilutive securities:

                               

Stock options and restricted shares

    858       -       -       2,903  

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

    167,349       165,162       165,727       167,715  
                                 

Net income (loss) per common share - basic

  $ 0.07     $ (0.06 )   $ (0.08 )   $ 0.00  
                                 

Net income (loss) per common share - diluted

  $ 0.07     $ (0.06 )   $ (0.08 )   $ 0.00  

 

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the three month period ended June 30, 2018,  3.2 million 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 six month period ended June 30, 2019, 869 thousand 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.

 

19

 

 

6.  Hedging Program and Derivatives

 

The derivative contracts the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  The Company's 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 June 30, 2019:

 

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2019 July - December

    4,097     $ 56.85  

2020 January - December

    3,023     $ 55.25  

2021 January - December

    2,051     $ 59.78  
                 

Basis Swaps

               

2019 July - December

    4,000     $ 2.98  

2020 January - December

    4,000     $ 2.98  

 

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

 

Fair Value of Derivative Contracts as of June 30, 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

  $ 517  

Derivatives – current

  $ 7,785  

Commodity price derivatives

 

Derivatives – long-term

    4,394  

Derivatives – long-term

    3,529  
        $ 4,911       $ 11,314  

 

 

Fair Value of Derivative Contracts as of December 31, 2018

 
   

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

  $ 9,602  

Derivatives – current

  $ 616  

Commodity price derivatives

 

Derivatives – long-term

    10,527  

Derivatives – long-term

    4,434  
        $ 20,129       $ 5,050  

 

20

 

 

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. The Company’s 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. The Company is 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 the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Company 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 June 30, 2019  

Assets:

                               

NYMEX fixed price derivative contracts

  $     $ 4,911     $     $ 4,911  

Total Assets

  $     $ 4,911     $     $ 4,911  

 

                               
Liabilities:                                

NYMEX fixed price derivative contracts

  $     $ 3,394     $     $ 3,394  

NYMEX basis differential swaps

                7,920       7,920  

Total Liabilities

  $     $ 3,394     $ 7,920     $ 11,314  

 

    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, 2018  

Assets:

                               

NYMEX fixed price derivative contracts

  $     $ 18,172     $     $ 18,172  

NYMEX basis differential swap contracts

                1,957       1,957  

Total Assets

  $     $ 18,172     $ 1,957     $ 20,129  
                                 

Liabilities:

                               

NYMEX fixed price derivative contracts

  $     $     $     $  

NYMEX basis differential swaps

                5,050       5,050  

Total Liabilities

  $     $ -     $ 5,050     $ 5,050  

 

The Company’s derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of June 30, 2019 and  December 31, 2018. Under fixed price swaps, the Company receives a fixed price for its production and pays a variable market price to the contract counter-party. Under a basis differential swap, if the market price is above the fixed price, the Company pays the counter-party, if the market price is below the fixed price, the counter-party pays the Company. The NYMEX-based fixed price derivative swaps and basis swaps 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, the Company enters the various inputs into a model and compares 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 the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the six months ended June 30, 2019.

 

Unobservable inputs at January 1, 2019

  $ (3,093 )

Changes in market value

    (5,470 )

Settlements during the period

    643  

Unobservable inputs at June 30, 2019

  $ (7,920 )

 

21

 

Nonrecurring Fair Value Measurements

 

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC 820-10 applies to certain nonfinancial 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.

 

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 the Company's 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

 

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheet through a Right of Use ("ROU")  asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed below. 

 

Our operating leases are reflected as operating lease ROU assets, operating lease liability - current and long-term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement and initial direct cost incurred less any lease incentives. Lease expense for operating leases is recognized on a straight-line basis over the lease term.

 

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 compressors and coolers 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 compressor and cooler 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.

 

22

 

 

Practical Expedients and Accounting Policy Elections

 

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

 

The components of our total lease expense for the three and six months ended June 30, 2019, the majority of which is included in lease operating expense, are as follows:

 

   

Three Months Ended June 30, 2019

   

Six Months Ended June 30, 2019

 

Operating lease cost

  $ 123     $ 240  

Short-term lease expense (1)

  $ 475     $ 938  

Total lease expense

  $ 598     $ 1,178  
                 

Short-term lease costs (2)

  $ 2,254     $ 3,771  

 

 

(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:
 

   

June 30, 2019

 

Operating lease ROU assets

  $ 518  

Operating lease liability - current

  $ 284  

Operating lease liabilities - long-term

  $ 229  

 

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

 

    June 30, 2019  

Weighted Average Remaining Lease Term (in years)

    5.42  

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 2019

  $ 298  

2020

    88  

2021

    49  

2022

    43  

2023

    39  

Thereafter

    99  

Total lease payments

    616  

Less imputed interest

    (103 )

Total lease liability

  $ 513  

 

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

 

   

Three Months Ended June 30, 2019

   

Six Months Ended June 30, 2019

 

Cash paid for amounts included in the measurement of lease liabilities

  $ 123     $ 240  

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

  $ 48     $ 735  

 

 

9. Commitments and Contingencies

 

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At June 30, 2019, the Company was not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its financial position or results of operations.

 

 

10. Subsequent Event

 

Subsequent to June 30, 2019, the Company entered into the following derivative contracts:

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2019 August - December

    1,438     $ 56.02  

2020 January - December

    754     $ 55.16  

2021 January - December

    756     $ 52.50  

 

 

 

 


 

 

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

 

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on March 15, 2019, and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

 

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, 2018, except for the adoption of the leasing standard which was effective January 1, 2019.

 

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. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development activities is critical in the maintenance and growth of our current production levels and associated reserves.

 

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 2019 will impact the amount of cash generated from operating activities, which will in turn impact our financial position.

 

During the six months ended June 30, 2019, the NYMEX future price for oil averaged $57.20 per Bbl as compared to $65.47 per Bbl in the same period of 2018. During the six months ended June 30, 2019, the NYMEX future spot price for gas averaged $2.69 per MMBtu compared to $2.84 per MMBtu in the same period of 2018. Prices closed on June 30, 2019 at $58.47 per Bbl of oil and $2.31 per MMBtu of gas, compared to closing on June 30, 2018 at $74.15 per Bbl of oil and $2.92 per MMBtu of gas.  On August 6, 2019, prices closed at $53.63 per Bbl of oil and $2.11 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, resulting in a reduction of the borrowing base under our credit facility.

 

24

Table of Contents

 

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 six months ended June 30, 2019 and 2018:

 

   

Oil - NYMEX

   

Gas - NYMEX

 
   

2019

   

2018

   

2019

   

2018

 

Average realized price (1)

  $ 52.04     $ 60.84     $ 0.92     $ 1.73  

Average NYMEX price

    57.20       65.47       2.69       2.84  

Differential

  $ (5.16 )   $ (4.63 )   $ (1.77 )   $ (1.11 )

                                                                                

(1) Excludes the impact of derivative activities.

 

At June 30, 2019, our derivative contracts consisted of NYMEX-based fixed price swaps and NYMEX basis 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, 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 85% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at December 31, 2018) from July 1, 2019 through December 31, 2019, 85% in 2020 and 75% in 2021. By 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 six months ended June 30, 2019, we realized a loss of $23.4  million, consisting of a loss of  $2.8 million on closed contracts and a loss of  $20.6 million related to open contracts. For the six months ended June 30, 2018, we realized a loss of $27.6 million consisting of a loss of $9.8  million on closed contracts and a loss of $17.8 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 June 30, 2019:

 

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2019 July - December

    4,097     $ 56.85  

2020 January - December

    3,023     $ 55.25  

2021 January - December

    2,051     $ 59.78  
                 

Basis Swaps

               

2019 July - December

    4,000     $ 2.98  

2020 January - December

    4,000     $ 2.98  

 

At June 30, 2019, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $6.4 million.

 

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities.  Based on the reserve information set forth in our reserve report as of December 31, 2018, our average annual estimated decline rate for our net proved developed producing reserves is 35%; 19%; 14%; 11% and 9% in 2019, 2020, 2021, 2022 and 2023, respectively, 11% 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.

 

25

Table of Contents

 

We had capital expenditures during the six months ended June 30, 2019 of $63.9 million related to our exploration and development activities. We have a capital expenditure budget for 2019 of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The 2019 budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The 2019 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.

 

The following table presents historical net production volumes for the three and six months ended June 30, 2019 and 2018:

 

 

   

Three Months Ended June 30,

   

Six Months Ended June 30,

 
   

2019

   

2018

   

2019

   

2018

 

Total production (MBoe)

    871       745       1,850       1,689  

Average daily production (Boepd)

    9,572       8,188       10,219       9,330  

% Oil

    71 %     59 %     69 %     62 %

 

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the three and six months ended June 30, 2019 and 2018, by our major operating regions:

 

 

   

Three Months Ended June 30,

   

Six Months Ended June 30,

 
   

2019

   

2018

   

2019

   

2018

 

Oil production (MBbls)

                               

Rocky Mountain

    321       247       766       578  

Permian/Delaware Basin

    280       158       469       394  

South Texas

    17       34       36       71  

Total

    618       439       1,271       1,043  

Gas production (MMcf)

                               

Rocky Mountain

    496       520       1,100       1045  

Permian/Delaware Basin

    316       452       768       971  

South Texas

    87       146       182       288  

Total

    899       1,118       2,050       2,304  

NGL production (MBbls)

                               

Rocky Mountain

    71       84       168       179  

Permian/Delaware Basin

    32       34       69       80  

South Texas

    -       2       -       3  

Total

    103       120       237       262  

Total production (MBoe) (1)

    871       745       1,850       1,689  

Average sales price per Bbl of oil (2)

                               

Rocky Mountain

  $ 54.66     $ 62.73     $ 51.41     $ 60.05  

Permian/Delaware Basin

    55.49       61.11       52.48       61.04  

South Texas

    63.08       68.84       59.74       66.21  

Composite

    55.25       62.62       52.04       60.84  

Average sales price per Mcf of gas (2)

                               

Rocky Mountain

  $ 0.42     $ 1.30     $ 1.06     $ 1.72  

Permian/Delaware Basin

    0.08       1.35       0.40       1.58  

South Texas

    2.02       2.22       2.24       2.27  

Composite

    0.45       1.44       0.92       1.73  

Average sales price per Bbl of NGL

                               

Rocky Mountain

  $ 3.33     $ 14.10     $ 5.79     $ 14.45  

Permian/Delaware Basin

    0.87       17.78       5.00       17.67  

South Texas

    0.00       23.12       15.41       21.53  

Composite

    2.57       15.29       5.57       15.51  

Average sales price per Boe (2)

    39.98       41.49       37.48       42.34  

Average cost of production per Boe produced (3)

                               

Rocky Mountain

  $ 6.51     $ 7.66     $ 5.02     $ 5.97  

Permian/Delaware Basin

    12.28       6.83       13.87       5.15  

South Texas

    18.03       13.98       16.27       13.62  

Composite

    9.33       7.87       8.61       6.22  

 

 

(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.

 

26

Table of Contents

 

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, borrowings under our credit facility, cash on hand, 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 financing on terms acceptable to us, if at all.  As of June 30, 2019, our borrowing base was $217.5 million with $34.5 million of availability under our credit facility.

 

Borrowings and Interest.  At June 30, 2019, we had a total of  $183.0 million outstanding under our credit facility and total indebtedness of $186.2 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.  As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

 

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, 2018, 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.

 

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 our exploration and development activities 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 and the amount that we are able to borrow under our credit facility may also decline. In addition, approximately 63% of our estimated proved reserves on a Boe basis at December 31, 2018 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 may be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition could be adversely affected.

 

Operational Update

 

Williston Basin, North Dakota

 

In North Dakota, the four-well Lillibridge NW pad (in which we own an average 33 percent working interest) was successfully completed and placed on production.  This four well pad has averaged 745 Boepd per well over its first month of production and continues to increase following our choke management protocol.

 

Raven Rig #1 has commenced drilling operations on our six-well Jore Fed Extension pad, in which we own an average 90 percent working interest.  Timing of first production from this pad will depend on weather, oil prices, and gas takeaway capacity.

 

Delaware Basin, West Texas

 

Operations in the Delaware Basin of West Texas continue to proceed smoothly. In Winkler County we successfully brought on line the Hackberry #201H (5,000-foot lateral in the Wolfcamp A-1), in which we own a  75 percent working interest. In Ward County, the two-well Woodberry pad (5,000-foot laterals in the Wolfcamp A-1 and 3rd Bone Spring) have been completed and are beginning their flowback with encouraging initial production rates. Both wells were drilled and completed under budget. On the Greasewood pad, in which we own 100 percent working interest, two 5,000-foot laterals in the Third Bone Spring and the Wolfcamp B are drilling the lateral sections with frac operations scheduled to commence in September 2019.  As the Greasewood wells represent the last remaining obligation wells for the Company for 2019, upon completion, the rig will be released giving us time to work on production optimization on the twenty plus producing wells in the area.

 

 

 

27

 

 

Results of Operations

 

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

 

 

   

Three Months Ended June 30,

   

Six Months Ended June 30,

 
   

2019

   

2018

   

2019

   

2018

 

Operating revenue (1):

                               

Oil sales

  $ 34,146     $ 27,472     $ 66,127     $ 63,466  

Gas sales

    408       1,608       1,881       3,985  

NGL sales

    265       1,835       1,321       4,058  

Other

    1       1       5       37  

Total operating revenues

  $ 34,820     $ 30,916     $ 69,334     $ 71,546  

Operating income

  $ 8,935     $ 10,797     $ 15,643     $ 30,757  

Oil sales (MBbls)

    618       439       1,271       1,043  

Gas sales (MMcf)

    899       1,118       2,050       2,304  

NGL sales (MBbls)

    103       120       237       262  

Oil equivalents (MBoe)

    871       745       1,850       1,689  

Average oil sales price (per Bbl)(1)

  $ 55.25     $ 62.62     $ 52.04     $ 60.84  

Average gas sales price (per Mcf)(1)

  $ 0.45     $ 1.44     $ 0.92     $ 1.73  

Average NGL sales price (per Bbl)

  $ 2.57     $ 15.29     $ 5.57     $ 15.51  

Average oil equivalent sales price (Boe) (1)

  $ 39.98     $ 41.49     $ 37.48     $ 42.34  

___________________

 

(1)

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

 

Comparison of Three Months Ended June 30, 2019 to Three Months Ended June 30, 2018

 

Operating Revenue. During the three months ended June 30, 2019, operating revenue increased to $34.8 million from $30.9 million for the same period of 2018. The increase in revenue was primarily due to higher oil sales volumes, partially offset by lower prices during the three months ended June 30, 2019 as compared to the same period of 2018. Higher oil sales volumes slightly offset by lower gas and NGL sales contributed  $11.1 million to operating revenue for the three months ended June 30, 2019. Lower realized commodity prices for all products had a negative impact of $7.2  million on operating revenue.

 

Oil sales volumes increased to 618 MBbl during the three months ended June 30, 2019 from 439 MBbl for the same period of 2018. The increase in oil sales volume was primarily due to new wells brought on line since the second quarter of 2018, offset by natural field declines and property sales. New wells brought on line since the second  quarter of 2018 contributed 353 MBbl for the three months ended June 30, 2019. Gas sales volumes decreased to 899 MMcf for the three months ended June 30, 2019 from 1,118 MMcf for the same period of 2018. The decrease in gas production was primarily due to field declines and continued pipeline constraints in West Texas and North Dakota, partially offset by new wells brought on line since the second quarter of 2018 which contributed 266 MMcf for the three months ended June 30, 2019. NGL sales volumes decreased to  103 MBbl for the three months ended June 30, 2019 from 120 MBbl for the same period of 2018. The decrease in NGL sales corresponds to the decrease in gas sales.

 

Lease Operating Expenses (“LOE”). LOE for the three months ended June 30, 2019 increased to $8.1 million from $5.7  million for the same period in 2018. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since June 30, 2018 as well as significant non-recurring cost related to the cost of shutting-in wells for frac protection and repair of frac damage to wells from offset fracs. LOE per Boe for the three months ended June 30, 2019 was $9.26 compared to $7.69 for the same period of 2018. The increase per Boe was due to higher costs offset by higher sales volumes for the three months ended June 30, 2019 as compared to the same period of 2018.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes  for the three months ended June 30, 2019  increased to $2.9  million from $2.5 million for the same period of 2018.  Production and ad valorem taxes for the three months ended June 30, 2019  and 2018 were 8% of total oil, gas and NGL sales. 

 

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Table of Contents

 

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, was generally flat at  $2.2 million for the three months ended June 30, 2019  and 2018. G&A expense per Boe, excluding stock-based compensation, was $2.51 for the quarter ended June 30, 2019 compared to $2.93 for the same period of 2018. The decrease per Boe was primarily due to  higher 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 the Company’s 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 June 30, 2019, stock-based compensation expense was $0.5 million compared to $0.9 million for the same period of 2018

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, including accretion of future site development, for the three months ended June 30, 2019 increased to $12.2 million from $8.8 million for the same period of 2018. The increase was primarily due to higher future development cost included in the June 30, 2019  reserve report,  capital expenditures in the first six months of 2019, as well as higher production volumes during the three months ended June 30, 2019 as compared to the same period of 2018.  DD&A expense per Boe for the three months ended June 30, 2019 was $13.99 compared to $11.86 in 2018. The increase in DD&A expense per Boe was primarily due to a higher full cost pool as well as higher capital cost in relation to reserve additions.

 

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 June 30, 2019, and June 30, 2018, 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. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.

 

Interest Expense. Interest expense for the three months ended June 30, 2019 increased to $2.8 million compared to $1.5 million for the same period of 2018. The increase in interest expense in 2019 was due to higher levels of debt during the three months ended June 30, 2019 as compared to the same period in 2018, as well as higher interest rates in 2019 as compared to 2018. For the three months ended June 30, 2019 the interest rate on our credit facility averaged 6.0% as compared to 5.1% for the same period of 2018.

 

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 June 30, 2019, and June 30, 2018. The net estimated value of our commodity derivative contracts was a net liability of approximately $6.4 million as of June 30, 2019. 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 June 30, 2019, we recognized a gain on our commodity derivative contracts of $5.6 million, consisting of a loss on closed contracts of  $1.9 million and a gain of $7.5 million related to open contracts. For the three months ended June 30, 2018, we recognized a loss on our commodity derivative contracts of $19.8 million, consisting of a loss of  $6.1 million on closed contracts and a loss of $13.7 million related to open contracts.

 

Income Tax Expense. For the three months ended June 30, 2019  and June 30, 2018 there was no income tax expense recognized due to our NOL carryforwards.

 

Comparison of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2018

 

Operating Revenue. During the six months ended June 30, 2019, operating revenue decreased to $69.3  million from $71.5 million for the same period of 2018. The decrease in revenue was primarily due to lower prices for all products offset by higher oil sales volumes during the six months ended June 30, 2019 as compared to the same period of 2018.  Lower realized commodity prices for all products negatively impacted operating revenue by $15.7 million  of which $11.2 million was attributable to oil. Lower gas and NGL prices had a negative impact on revenue of approximately $4.5 million for the six months ended June 30, 2019. During the six months ended June 30, 2019 gas and NGL sales were impacted by a very weak pricing environment as well as plant and pipeline constraints. Higher oil sales volumes contributed $13.8 million to operating revenue for the six months ended June 30, 2019 offset by lower gas and NGL sales which negatively impacted revenue by $0.4 million.

 

Oil sales volumes increased to 1,271 MBbl during the six months ended June 30, 2019 from 1,043 MBbl for the same period of 2018. The increase in oil sales volume was primarily due to new wells brought on line since the second quarter of 2018, offset by natural field declines and property sales. New wells brought on line since the second quarter of 2018 contributed 681 MBbl for the six months ended June 30, 2019. Gas sales volumes decreased to 2,050  MMcf for the six months ended June 30, 2019 from 2,304 MMcf for the same period of 2018. The decrease in gas and NGL sales was primarily due to a  lack of infrastructure and  pipeline and plant constraints offset by new wells brought on line since the second quarter of 2018 which contributed 520 MMcf for the six months ended June 30, 2019. NGL sales volumes decreased to 237 MBbl for the six months ended June 30, 2019 from 262 MBbl for the same period of 2018. The decrease in NGL sales corresponds to the decrease in gas sales.

 

Lease Operating Expenses (“LOE”). LOE for the six months ended June 30, 2019 increased to $15.8 million from $10.3 million for the same period in 2018. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since June 30, 2018 as well as significant non-recurring cost related to the cost of shutting-in wells for frac protection and repair of frac damage to wells from offset fracs. LOE per Boe for the six months ended June 30, 2019 was $8.54 compared to $6.10 for the same period of 2018. The increase per Boe was due to higher costs offset by higher sales volumes for the six months ended June 30, 2019 as compared to the same period of 2018.

 

 

 

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months ended June 30, 2019 increased to $6.0 million from $5.6 million for the same period in 2018. The increase was primarily due to higher production volumes. Production and ad valorem taxes for the six months ended June 30, 2019 were 9% of total oil, gas and NGL sales compared to 8% for the same period of 2018. The increase in the percentage of taxes of total oil, gas and NGL sales was due to increased production in North Dakotas which has a higher tax rate. 

 

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, increased to $4.5 million for the six months ended June 30, 2019 compared to $4.3 million for the same period of 2018. G&A expense per Boe, excluding stock-based compensation, was $2.45 for the six months ended June 30, 2019 compared to $2.56 for the same period of 2018. The decrease per Boe was primarily due to higher G&A expense offset by higher 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 the Company’s common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the six months ended June 30, 2019 stock-based compensation expense was $0.9 million compared to $1.5 million for the same period of 2018. The decrease is due to grants that have fully vested and the related expense already recognized.

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, including accretion of future site development, for the six months ended June 30, 2019 increased to $25.8 million from $19.1 million for the same period of 2018. The increase was primarily due to higher future development costs included in the June 30, 2019  reserve report,  capital expenditures in the first six months of 2019, as well as higher production volumes during the three months ended June 30, 2019 as compared to the same period of 2018. DD&A expense per Boe for the six months ended June 30, 2019 was $13.93 compared to $11.31 in 2018. The increase was primarily the result of  higher future development costs.

 

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 June 30, 2019, and June 30, 2018, 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. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.

 

Interest Expense. Interest expense for the six months ended June 30, 2019 increased to $5.7 million compared to $2.7 million for the same period of 2018. The increase in interest expense in 2019 was due to higher levels of debt during the six months ended June 30, 2019 as compared to the same period in 2018 as well as higher interest rates in 2019 as compared to 2018. The average interest rate during the six months ended June 30, 2019 was 6.0% compared to 5.0% for the same period of 2018.

 

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. 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 as of June 30, 2019 and 2018 consisted of NYMEX-based fixed price swaps and basis differential swaps. The net estimated value of our commodity derivative contracts was a net liability of approximately $6.4 million as of June 30, 2019. 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 six months ended June 30, 2019, we recognized a loss on our commodity derivative contracts of $23.4 million, consisting of a loss on closed contracts of $2.8 million and a loss of $20.6 million related to open contracts. For the six months ended June 30, 2018, we recognized a loss on our commodity derivative contracts of $27.6 million, consisting of a loss of $9.8 million on closed contracts and a loss of $17.8 million related to open contracts.

 

Income Tax Expense. For the six months ended June 30, 2019 and 2018 there was no income tax expense recognized as a result of our NOL carryforwards.

 

 

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Table of Contents

 

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.

 

Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative contracts and if appropriate opportunities are available, the sale of debt or equity securities, although we may not be able to complete any such transactions on terms acceptable to us, if at all. Based upon current oil, gas and NGL price expectations and our commodity derivatives positions, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our revolving credit facility will provide us sufficient liquidity to fund our operations for the remainder of 2019 including our planned capital expenditures.

 

Working Capital (Deficit). At June 30, 2019, our current liabilities of $67.8 million exceeded our current assets of $32.0 million resulting in a working capital deficit of $35.8 million. This compares to a working capital deficit of $13.6 million at December 31, 2018. Current assets at June 30, 2019 primarily consisted of  accounts receivable of  $30.7 million, current amount of our derivative asset of  $0.5 million and other current assets of $0.8 million. Current liabilities at June 30, 2019 primarily consisted of trade payables of  $41.1 million, revenues due third parties of $17.1 million, current maturities of long-term debt of $0.3 million, the current amount of our derivative liability of $7.8 million and accrued expenses and other of  $1.6 million. The working capital deficit is expected to be funded by cash flows from operations and borrowings under our credit facility.

 

 

Capital Expenditures. Capital expenditures for the six months ended June 30, 2019 and 2018 were $63.6 million and $76.1 million, respectively.

 

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

 

 

   

Six Months Ended June 30,

 
   

2019

   

2018

 
   

(In thousands)

 

Expenditure category:

               

Exploration/Development

  $ 63,483     $ 53,623  

Acquisitions

    -       21,769  

Facilities and other

    94       729  

Total

  $ 63,577     $ 76,121  

 

During the six months ended June 30, 2019 our expenditures were primarily for development of our existing properties. For the six months ended June 30, 2018, expenditures were primarily for the development of our existing properties  and the acquisition of leaseholds. Capital expenditures for the six months ended June 30,  2019  of $63.6 million includes $3.2 million for a decrease in capital expenditures in accounts payable, net capital expenditures of $60.4 million was applicable to our 2019 capital expenditures budget.  We anticipate making capital expenditures in 2019 of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The 2019 budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The 2019 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.

 

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Table of Contents

 

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: 

 

 

   

Six Months Ended June 30,

 
   

2019

   

2018

 
   

(In thousands)

 

Net cash provided by operating activities

  $ 42,699     $ 45,286  

Net cash used in investing activities

    (46,772 )     (73,709 )

Net cash provided by financing activities

    3,206       27,687  

Total

  $ (867 )   $ (736 )

 

Operating activities for the six months ended June 30, 2019 provided $42.7 million in cash compared to providing $45.3 million in the same period of 2018. Reductions in operating income offset by changes in operating assets and liabilities accounted for most of these funds. Investing activities used $46.8 million during the six months ended June 30, 2019  primarily for the development of our existing properties. Investing activities used $73.7 million during the six months ended June 30, 2018 primarily for the development of our existing properties and acquisition of leasehold, partially offset by proceeds from the sale of oil and gas properties.  Financing activities provided $3.2 million for the six months ended June 30, 2019 compared to providing $27.7 million for the same period of 2018. Funds provided during the six months ended June 30, 2019  and 2018, were primarily net proceeds from borrowings under our credit facility. 

  

Future Capital Resources. Our principal sources of capital going forward are cash flows from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing derivative instruments and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all.

 

Cash from operating activities is dependent upon commodity prices and production volumes.  Depressed commodity prices have reduced, and further decreases in commodity prices from current levels could reduce our cash flows from operations.  This could cause us to alter our business plans, including reducing our exploration and development plans.  Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced.  In the future, we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including availability of capital and the risk that no commercially productive oil and gas reservoirs will be found.  If our proved reserves decline in the future, our production could also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility could also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 63% of our total estimated proved reserves on a Boe basis at December 31, 2018 were classified as undeveloped.

 

We have in the past, and may in the future, sell producing properties. We have also sold debt and equity securities in the past, and may sell additional debt and equity securities in the future when the opportunity presents itself.

 

Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:

 

 

Long-term debt, and

 

Operating leases.

 

31

Table of Contents

 

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of June 30, 2019:

 

 

   

Payments due in twelve month periods ending:

 

Contractual Obligations

 

Total

   

June 30, 2020

   

June 30, 2021-2022

   

June 30, 2023-2024

   

Thereafter

 

Long-term debt (1)

  $ 186,227     $ 274     $ 183,590     $ 2,363     $ -  

Interest on long-term debt (2)

    30,523       10,585       19,823       115       -  

Lease obligations (3)

    513       284       119       68       42  

Total

  $ 217,263     $ 11,143     $ 203,532     $ 2,546     $ 42  

                                                       

 

(1)

These amounts represent the balances outstanding under our credit facility and the real estate lien note. These payments assume that we will not borrow additional funds.

 

(2)

Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.

 

(3)

Lease obligations.

 

We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At June 30, 2019, our reserve for these obligations totaled $7.8 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.

 

Off-Balance Sheet Arrangements. At June 30, 2019, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

 

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 June 30, 2019, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

 

Long-Term Indebtedness.

 

Long-term debt consisted of the following:

 

 

   

June 30, 2019

   

December 31, 2018

 

Credit facility

  $ 183,000     $ 180,000  

Real estate lien note

    3,227       3,358  
      186,227       183,358  

Less current maturities

    (274 )     (267 )
    $ 185,953     $ 183,091  

 

Credit Facility

 

The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility.  As of June 30, 2019$183.0 million was outstanding under the Credit Facility.

 

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At June 30, 2019, we had a borrowing base of $217.5 million. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge additional oil and gas properties or other assets as collateral. We do not currently have any substantial unpledged assets and we may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to fail to be in compliance with the financial covenants described below. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount.  Outstanding amounts under the credit facility bear interest at (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, 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) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or, (ii) if we elect, LIBOR plus, in each case, 2.5%-3.5% depending on the utilization of the borrowing base. At June 30, 2019, the interest rate on the credit facility was approximately 5.7% assuming LIBOR borrowings.

 

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Table of Contents

 

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

 

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. We have also granted our lenders a security interest in our headquarters building.

 

Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements.  We are required to maintain a current ratio, as defined in the 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.  We are 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 is defined as the ratio of consolidated current assets to consolidated current liabilities.  For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20.  The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date.  For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with our headquarters building and obligations with respect to surety bonds and derivative contracts.

 

At June 30, 2019, we were in compliance with all of these financial covenants. As of June 30, 2019, the interest coverage ratio was 8.12 to 1.00, the total debt to EBITDAX ratio was 2.24 to 1.00, and our current ratio was 1.10 to 1.00.

 

The 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;

 

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 credit facility also contains certain additional covenants including requirements that:

 

 

100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and

 

if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility.

 

The 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. As of June 30, 2019, we were in compliance with all of the terms of our credit facility.

 

33

Table of Contents

 

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 note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of June 30, 2019 and December 31, 2018, $3.2 million and $3.4 million, respectively, were outstanding on the note.

 

Hedging Activities

 

Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. We have entered into commodity swaps on approximately 85% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at December 31, 2018) from July 1 through December 31, 2019, 85% for 2020 and 75% for 2021.

 

By removing a portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations.  However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged.  We have sustained, and in the future, will sustain, losses on our derivative contracts when 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.

 

If the disparity between our contract prices and market prices continues, we will sustain gains or losses on our derivative contracts. While gains and losses resulting from the periodic mark to market of our open contracts do not impact our cash flow from operations, gains and losses from settlements of our closed contracts do impact our cash flow from operations. 

 

In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices.  If the prices at which we hedge future production are significantly lower than our existing derivative contracts, our future cash flow from operations would likely be materially lower.  

 

34

Table of Contents

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

 

Commodity Price Risk

 

As an independent oil and gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for our oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the six months ended June 30, 2019, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $6.9 million. If commodity prices decline from current levels, the impact on operating revenues and cash flow, could be much more significant. However, we do have derivative contracts in place that will mitigate the impact of low commodity prices.

 

Derivative Instrument Sensitivity

 

At June 30, 2019, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $6.4 million. The fair market value of our commodity derivative contracts is sensitive to changes in the market price for oil and gas. 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.

 

Interest Rate Risk

 

We are subject to interest rate risk associated with borrowings under our credit facility.  As of June 30, 2019, we had $183.0 million of outstanding indebtedness under our credit facility. Outstanding amounts under the credit facility bear interest at (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below and (b) at all other times, 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) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or, (ii) if we elect LIBOR plus 2.5%-3.5%, depending on the utilization of the borrowing base. At June 30, 2019, the interest rate on the credit facility was approximately 5.7% assuming LIBOR borrowings. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.8 million on an annual basis, based on our outstanding indebtedness as of June 30, 2019.

 

Item 4. Controls and Procedures.

 

As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas’ “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were effective.

 

There were no changes in our internal controls over financial reporting during the three months ended June 30, 2019 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

 

35

Table of Contents

 

PART II

 

Item 1.    Legal Proceedings.

 

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At June 30, 2019, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse impact on its financial position or results of operations.

 

Item 1A. Risk Factors.

 

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

 

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

 

 None

 

Item 3.    Defaults Upon Senior Securities.

 

 None

 

Item 4.    Mine Safety Disclosure.

 

 Not applicable

 

Item 5.    Other Information.

 

 None

 

Item 6.    Exhibits.

 

 

(a)

Exhibits

 

 

Exhibit 31.1

Certification - Robert L.G. Watson, CEO

 

Exhibit 31.2

Certification - Steven P. Harris, CFO

 

Exhibit 32.1

Certification pursuant to 18 U.S.C. Section 1350 - Robert L.G. Watson, CEO

 

Exhibit 32.2

Certification pursuant to 18 U.S.C. Section 1350 - Steven P. Harris, CFO

 

36

Table of Contents

 

ABRAXAS PETROLEUM CORPORATION

 

SIGNATURES

 

 

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

 

 

 

Date

August 9, 2019

 

By: /s/Robert L.G. Watson                                                    

 

 

 

ROBERT L.G. WATSON,

 

 

 

President and

 

 

 

Principal Executive Officer

 

Date

August 9, 2019

 

By: /s/Steven P. Harris                                                   

 

 

 

STEVEN P. HARRIS

 

 

 

Vice President and

 

 

 

Principal Financial Officer

 

Date

August 9, 2019

 

By: /s/G. William Krog, Jr.                                             

 

 

 

G. WILLIAM KROG, JR.,

 

 

 

Vice President and

 

 

 

Principal Accounting Officer

 

37

ex_140176.htm

Exhibit 31.1

 

CERTIFICATIONS

 

I, Robert L. G. Watson, certify that:    

    

 

1.

I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation.

 

 

2.

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

 

 

3.

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

 

 

4.

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

 

 

(a)

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

 

 

(b)

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

 

 

(c)

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

 

 

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

 

5.

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

 

 

(a)

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

 

 

(b)

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

 

Date: August 9, 2019

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and

Principal Executive Officer

ex_140177.htm

Exhibit 31.2

 

CERTIFICATIONS

 

I, Steven P. Harris, certify that:    

    

 

1.

I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation.

 

 

2.

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

 

 

3.

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

 

 

4.

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

 

 

(a)

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

 

 

(b)

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

 

 

(c)

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

 

 

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

 

5.

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

 

 

(a)

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

 

 

(b)

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

 

Date: August 9, 2019

/s/ Steven P. Harris

Steven P. Harris

Vice President and

Principal Financial Officer

ex_140178.htm

Exhibit 32.1

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

 

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

 

 

(1)

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

 

(2)

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

 

 

 

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and Chief Executive Officer

August 9, 2019

 

 

 

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

 

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

ex_140179.htm

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

 

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

 

 

(1)

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

 

(2)

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

 

 

 

/s/Steven P. Harris

Steven P. Harris

Vice President and Chief Financial Officer

August 9, 2019

 

 

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

 

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

v3.19.2
Document And Entity Information - shares
6 Months Ended
Jun. 30, 2019
Aug. 06, 2019
Document Information [Line Items]    
Entity Registrant Name ABRAXAS PETROLEUM CORP  
Entity Central Index Key 0000867665  
Trading Symbol axas  
Current Fiscal Year End Date --12-31  
Entity Filer Category Accelerated Filer  
Entity Current Reporting Status Yes  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   168,452,060
Entity Shell Company false  
Document Type 10-Q  
Document Period End Date Jun. 30, 2019  
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q2  
Amendment Flag false  
Title of 12(b) Security Common Stock  
v3.19.2
Condensed Consolidated Balance Sheets (Current Period Unaudited) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Current assets:    
Cash and cash equivalents $ 867
Accounts receivable:    
Joint owners, net 12,522 17,110
Oil and gas production sales 17,023 21,991
Other 1,114 535
Total accounts receivable 30,659 39,636
Derivative asset - short-term 517 9,602
Other current assets 781 626
Total current assets 31,957 50,731
Proved oil and gas properties, full cost method 1,135,758 1,091,905
Other property and equipment 39,548 39,453
Total 1,175,306 1,131,358
Less accumulated depreciation, depletion, amortization and impairment (794,056) (768,140)
Total property and equipment, net 381,250 363,218
Operating lease ROU asset 518
Deferred financing fees, net 964 1,149
Derivative asset, long-term 4,394 10,527
Other assets 265 265
Total assets 419,348 425,890
Current liabilities:    
Accounts payable 41,092 39,571
Joint interest oil and gas production payable 17,052 23,063
Accrued interest 312 335
Other accrued expenses 1,047 511
Operating lease liability - current 284
Derivative liability, current 7,785 616
Current maturities of long-term debt 274 267
Total current liabilities 67,846 64,363
Long-term debt – less current maturities 185,953 183,091
Operating lease liabilities - long-term 229
Derivative liability long-term 3,529 4,434
Future site restoration 7,763 7,492
Total liabilities 265,320 259,380
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; 168,452,060 and 166,713,784 issued and outstanding at June 30, 2019 and December 31, 2018, respectively 1,684 1,667
Additional paid-in capital 419,122 417,844
Accumulated deficit (266,778) (253,001)
Total stockholders’ equity 154,028 166,510
Total liabilities and stockholders’ equity $ 419,348 $ 425,890
v3.19.2
Condensed Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares
Jun. 30, 2019
Dec. 31, 2018
Preferred stock, par value (in dollars per share) $ 0.01 $ 0.01
Preferred stock, authorized (in shares) 1,000,000 1,000,000
Preferred stock, issued (in shares) 0 0
Preferred stock, outstanding (in shares) 0 0
Common stock, par value (in dollars per share) $ 0.01 $ 0.01
Common stock, authorized (in shares) 400,000,000 400,000,000
Common stock, issued (in shares) 168,452,060 166,713,784
Common stock, outstanding (in shares) 168,452,060 166,713,784
v3.19.2
Condensed Consolidated Statements of Operations (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Revenues:        
Other $ 1 $ 1 $ 5 $ 37
Revenues 34,820 30,916 69,334 71,546
Operating costs and expenses:        
Lease operating 8,066 5,730 15,800 10,299
Production and ad valorem taxes 2,926 2,485 6,024 5,598
Rig expense 672
Depreciation, depletion, amortization and accretion 12,188 8,839 25,762 19,099
General and administrative (including stock-based compensation of $521; $879; $894 and $1,466, respectively) 2,705 3,065 5,433 5,793
Total operating cost and expenses 25,885 20,119 53,691 40,789
Operating income 8,935 10,797 15,643 30,757
Other (income) expense:        
Interest expense 2,765 1,492 5,732 2,691
Amortization of deferred financing fees 128 111 249 207
(Gain) 1oss on derivative contracts (5,636) 19,763 23,439 27,646
Gain on sale of non-oil and gas assets (15) (12)
Total other (income) expense (2,743) 21,351 29,420 30,532
Income (loss) before income tax 11,678 (10,554) (13,777) 225
Income tax (expense) benefit 0 0 0 0
Net income (loss) $ 11,678 $ (10,554) $ (13,777) $ 225
Net income (loss) per common share - basic (in dollars per share) $ 0.07 $ (0.06) $ (0.08) $ 0
Net income (loss) per common share - diluted (in dollars per share) $ 0.07 $ (0.06) $ (0.08) $ 0
Weighted average shares outstanding:        
Basic (in shares) 166,491 165,162 165,727 164,812
Diluted (in shares) 167,349 165,162 165,727 167,715
Oil Revenues [Member]        
Revenues:        
Revenues $ 34,146 $ 27,472 $ 66,127 $ 63,466
Gas Revenues [Member]        
Revenues:        
Revenues 408 1,608 1,881 3,985
Natural Gas Liquids Revenues [Member]        
Revenues:        
Revenues $ 265 $ 1,835 $ 1,321 $ 4,058
v3.19.2
Condensed Consolidated Statements of Operations (Unaudited) (Parentheticals) - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Stock-based compensation $ 521 $ 879 $ 894 $ 1,466
v3.19.2
Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($)
$ in Thousands
Common Stock [Member]
Additional Paid-in Capital [Member]
Retained Earnings [Member]
Total
Balance (in shares) at Dec. 31, 2017 165,889,901      
Balance at Dec. 31, 2017 $ 1,659 $ 415,471 $ (310,822) $ 106,308
Net (loss) income 225 225
Stock-based compensation 1,466 1,466
Stock options exercised (in shares) 145,253      
Stock options exercised $ 2 14 16
Restricted stock issued, net of forfeitures (in shares) 676,056      
Restricted stock issued, net of forfeitures $ 6 (7) (1)
Balance (in shares) at Jun. 30, 2018 166,711,210      
Balance at Jun. 30, 2018 $ 1,667 416,944 (310,597) 108,014
Balance (in shares) at Mar. 31, 2018 165,881,694      
Balance at Mar. 31, 2018 $ 1,659 416,068 (300,043) 117,684
Net (loss) income (10,554) (10,554)
Stock-based compensation 879 879
Stock options exercised (in shares) 133,335      
Stock options exercised $ 1 4 5
Restricted stock issued, net of forfeitures (in shares) 696,181      
Restricted stock issued, net of forfeitures $ 7 (7)
Balance (in shares) at Jun. 30, 2018 166,711,210      
Balance at Jun. 30, 2018 $ 1,667 416,944 (310,597) $ 108,014
Balance (in shares) at Dec. 31, 2018 166,713,784     166,713,784
Balance at Dec. 31, 2018 $ 1,667 417,844 (253,001) $ 166,510
Net (loss) income (13,777) (13,777)
Stock-based compensation 894 894
Stock options exercised (in shares) 423,369      
Stock options exercised $ 4 397 401
Restricted stock issued, net of forfeitures (in shares) 1,314,907      
Restricted stock issued, net of forfeitures $ 13 (13)
Balance (in shares) at Jun. 30, 2019 168,452,060     168,452,060
Balance at Jun. 30, 2019 $ 1,684 419,122 (266,778) $ 154,028
Balance (in shares) at Mar. 31, 2019 167,136,398      
Balance at Mar. 31, 2019 $ 1,671 418,614 (278,456) 141,829
Net (loss) income 11,678 11,678
Stock-based compensation 521 521
Stock options exercised (in shares) 755      
Stock options exercised
Restricted stock issued, net of forfeitures (in shares) 1,314,907      
Restricted stock issued, net of forfeitures $ 13 (13)
Balance (in shares) at Jun. 30, 2019 168,452,060     168,452,060
Balance at Jun. 30, 2019 $ 1,684 $ 419,122 $ (266,778) $ 154,028
v3.19.2
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)
$ in Thousands
6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Operating Activities    
Net (loss) income $ (13,777) $ 225
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:    
Gain on sale of non-oil and gas assets (12)
Net loss on derivative contracts 23,439 27,646
Net cash settlements (paid) received on derivative contracts (1,957) (9,847)
Depreciation, depletion, amortization and accretion 25,762 19,099
Amortization of deferred financing fees 249 207
Stock-based compensation 894 1,466
Settlement of asset retirement obligation (386)
Changes in operating assets and liabilities:    
Accounts receivable 8,977 (631)
Other assets (444) 1,381
Accounts payable and accrued expenses (58) 5,752
Net cash provided by operating activities 42,699 45,286
Investing Activities    
Capital expenditures, including purchases and development of properties (63,577) (73,818)
Proceeds from the sale of oil and gas properties 16,805 82
Proceeds from the sale of non-oil and gas assets 27
Net cash used in investing activities (46,772) (73,709)
Financing Activities    
Proceeds from long-term borrowings 23,000 35,000
Payments on long-term borrowings (20,131) (7,129)
Deferred financing fees (64) (199)
Exercise of stock options 401 15
Net cash provided by financing activities 3,206 27,687
Decrease in cash and cash equivalents (867) (736)
Cash and cash equivalents at beginning of period 867 1,618
Cash and cash equivalents at end of period 882
Supplemental disclosures of cash flow information:    
Interest paid 5,778 2,577
Non-cash investing and financing activities    
Change in capital expenditures included in accounts payable (decrease) increase (3,248) 2,267
Change in asset retirement obligations $ 51 $ 36
v3.19.2
Note 1 - Basis of Presentation
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Basis of Presentation and Significant Accounting Policies [Text Block]
1.
Basis of Presentation
 
The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form
10
-K for the year ended
December 31, 2018
 filed with the SEC on
March 15, 2019.
Such policies have been continued without change, except as noted herein, due to the change in lease accounting adopted in the current period. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All material items included in those notes have
not
changed except as a result of normal transactions in the interim, or as disclosed within this report. 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
and
six
month periods ended
June 30, 2019
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 the Company’s Annual Report on Form
10
-K for the year ended
December 31, 2018
.
 
Reclassifications
 
Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications had
no
effect on the Company’s previously reported results of operations.
 
Consolidation Principles
 
The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC (“Raven Drilling”).
 
Rig Accounting
 
In accordance with SEC Regulation S-
X,
no
income is  recognized in connection with contractual drilling services performed in connection with properties in which the Company or its 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.
 
 
Recently Adopted Lease Accounting Standard
 
In
February 2016,
an accounting standards update was issued that requires an entity to recognize a right-of-use (“ROU”) asset and lease liability for certain leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.
 
The new standard was effective for us in the
first
quarter of 
2019
 and we adopted the new standard using a modified retrospective approach, with the date of initial application on
January 1, 2019.
Consequently, upon transition, we recognized an ROU asset (or operating lease right-of-use asset) and a lease liability with
no
retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to:
 
 
Not
apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of
12
months or less);
 
Not
reassess whether a contract contains a lease, lease classification and initial direct costs; and
 
Not
reassess certain land easements in existence prior to
January 1, 2019.
 
The impact of adoption of this new standard on our balance sheet was as follows:
 
 
 
January 1, 2019
 
Operating lease ROU asset
 
$
687
 
Operating lease liability - current
 
$
(108
)
Operating lease liability - long-term
 
$
(579
)
 
Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are
not
within the scope of the standards update. For more information, see Note
8.
 
Stock-Based Compensation and Option Plans
 
Stock Options
 
The Company currently utilizes 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 the Company’s stock-based compensation expense related to stock options for the periods presented: 
 
 
Three Months Ended
 
 
Six Months Ended
 
June 30,
 
 
June 30,
 
2019
 
 
2018
 
 
2019
 
 
2018
 
$
74
 
 
$
574
 
 
$
225
 
 
$
914
 
 
The following table summarizes the Company’s stock option activity for the
six
months ended
June 30, 2019
:
 
 
 
Number of Shares
 
 
Weighted Average Option Exercise Price Per Share
 
 
Weighted Average Grant Date Fair Value Per Share
 
Outstanding, December 31, 2018
 
 
7,549
 
 
$
2.37
 
 
$
1.68
 
Granted
 
 
 
 
 
 
 
 
 
Exercised
 
 
(469
)
 
$
0.98
 
 
$
0.68
 
Forfeited
 
 
(572
)
 
$
3.00
 
 
$
2.12
 
Outstanding, June 30, 2019
 
 
6,508
 
 
$
2.41
 
 
$
1.71
 
    
As of
June 30, 2019
, there was approximately
$0.3
 million of unamortized compensation expense related to outstanding stock options that will be recognized from 
2019
 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 the Company 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 the Company’s restricted stock activity for the
six
months ended
June 30, 2019
 
 
 
 
Number of Shares (thousands)
 
 
Weighted Average Grant Date Fair Value Per Share
 
Unvested, December 31, 2018
 
 
827
 
 
$
2.15
 
Granted
 
 
1,315
 
 
$
1.34
 
Vested/Released
 
 
(228
)
 
$
2.22
 
Forfeited
 
 
 
 
$
-
 
Unvested, June 30, 2019
 
 
1,914
 
 
$
1.59
 
 
The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented: 
 
 
Three Months Ended
 
 
Six Months Ended
 
June 30,
 
 
June 30,
 
2019
 
 
2018
 
 
2019
 
 
2018
 
$
277
 
 
$
221
 
 
$
420
 
 
$
468
 
 
As of
June 30, 2019
, there was approximately
$2.5
 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized from 
2019
 through
2022.
 
Performance Based Restricted Stock
 
The Company issues 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 the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of the Company’s 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, 2018
 
 
405
 
 
$
2.37
 
Granted
 
 
803
 
 
$
1.34
 
Vested/Released
 
 
 
 
$
-
 
Forfeited
 
 
 
 
$
-
 
Unvested, June 30, 2019
 
 
1,208
 
 
$
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 the Company's 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 the Company’s stock-based compensation expense related to performance based restricted stock for the periods presented: 
 
 
Three Months Ended
 
 
Six Months Ended
 
June 30,
 
 
June 30,
 
2019
 
 
2018
 
 
2019
 
 
2018
 
$
170
 
 
$
84
 
 
$
249
 
 
$
84
 
 
As of
June 30, 2019
, there was approximately
$1.6
 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 
2019
 through
2022.
 
Oil and Gas Properties
 
The Company follows 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At
June 30, 2019
 and
2018
, our net capitalized costs of oil and gas properties did
not
exceed the cost ceiling of our estimated proved reserves.
 
In
May 2019,
the Company closed on the sale of its non-operated assets in the Bakken. Proceeds from the sale of approximately
$15.8
million were used to reduce outstanding indebtedness under its credit facility. In accordance with full cost accounting rules, the sale was
not
deemed to be singnificant,; therefore,
no
gain or loss was recorded and the proceeds were credited to the full cost pool.
 
Restoration, Removal and Environmental Liabilities
 
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and
may
require the Company 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.
 
The Company accounts 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 the Company’s future site restoration obligation transactions for the
six
months ended
June 30, 2019
 and the year ended
December 31, 2018
 
 
 
 
June 30, 2019
 
 
December 31, 2018
 
Beginning future site restoration obligation
 
$
7,492
 
 
$
8,775
 
New wells placed on production and other
 
 
80
 
 
 
612
 
Deletions related to property disposals and plugging costs
 
 
(487
)
 
 
(2,270
)
Accretion expense
 
 
220
 
 
 
516
 
Revisions and other
 
 
458
 
 
 
(141
)
Ending future site restoration obligation
 
$
7,763
 
 
$
7,492
 
v3.19.2
Note 2 - Revenue From Contracts With Customers
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Revenue from Contract with Customer [Text Block]
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. The Company's 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. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.
 
Oil sales
 
The Company's oil sales contracts are generally structured such that it sells its 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. The Company recognizes 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 the Company's gas processing contracts, it delivers 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 the Company 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 the Company receives.
 
In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.
 
Imbalances
 
The Company utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had
no
material gas imbalances at
June 30, 2019
 and
2018
.
 
Disaggregation of Revenue
 
The Company is focused on the development of oil and natural gas properties primarily located in the following
three
operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the tables below.
 
 
   
Three Months Ended June 30,
 
   
2019
   
2018
 
   
Oil
   
Gas
   
NGL
   
Oil
   
Gas
   
NGL
 
Operating Regions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian/Delaware Basin
  $
15,562
    $
24
    $
27
    $
9,664
    $
609
    $
613
 
Rocky Mountain
  $
17,567
    $
208
    $
238
    $
15,479
    $
674
    $
1,180
 
South Texas
  $
1,017
    $
176
    $
-
    $
2,329
    $
325
    $
42
 
 
   
Six Months Ended June 30,
 
   
2019
   
2018
 
   
Oil
   
Gas
   
NGL
   
Oil
   
Gas
   
NGL
 
Operating Regions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian/Delaware Basin
  $
24,626
    $
311
    $
340
    $
24,039
    $
1,528
    $
1,411
 
Rocky Mountain
  $
39,367
    $
1,162
    $
978
    $
34,719
    $
1,802
    $
2,583
 
South Texas
  $
2,134
    $
408
    $
3
    $
4,708
    $
655
    $
64
 
 
Significant Judgments
 
Principal versus agent
 
The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to
third
-party customers on the Company's behalf, such as the Company's 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 the Company's product sales are short-term in nature with a contract term of
one
year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic
606
-
10
-
50
-
14
exempting the Company 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, the Company has utilized the practical expedient in ASC Topic
606
-
10
-
50
-
14
(a) which states the Company is
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 the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records 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 the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do
not
give rise to contract assets or liabilities under ASU
2014
-
09.
At
June 30, 2019
 and
December 31, 2018
, our receivables from contracts with customers were
$17.0
 million and
$22.0
 million, respectively.
 
Prior-period performance obligations
 
The Company records 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, the Company is 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.
 
The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have
not
been significant. For the
three
and
six
months ended
June 30, 2019
, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was
not
material.
 
v3.19.2
Note 3 - Income Taxes
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Income Tax Disclosure [Text Block]
3.
  Income Taxes
 
The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.
 
For the
three
and
six
months ended
June 30, 2019
 and
2018
, there was
no
income tax benefit due to net operating loss carryforwards ("NOLs") and the Company recorded a full valuation allowance against its net deferred taxes. 
 
At
December 31, 2018
, the Company had, subject to the limitation discussed below,
$245.2
 million of pre-
2018
NOLs and
$46.8
million of
2018
NOL carryforwards for U.S. tax purposes.  The Company's pre-
2018
NOLs will expire in varying amounts from
2023
through
2037,
if
not
utilized; and can offset
100%
of future taxable income for regular tax purposes. Any NOLs arising after
January 1, 2018
can generally be carried forward indefinitely and can offset up to
80%
of future taxable income for regular tax purposes. Effective
January 1, 2018
the alternative minimum tax
no
longer applies to corporations.
 
The use of the Company's NOLs will be limited if there is an "ownership change" in its 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
June 30, 2019
, the Company has
not
had an ownership change as defined by Section
382.
Given historical losses, uncertainties exist as to the future utilization of the NOL. Therefore, the Company established a valuation allowance of
$67.3
 million for deferred tax assets at
December 31, 2018
 
As of
June 30, 2019
, the Company did
not
have any accrued interest or penalties related to uncertain tax positions. The tax years
2013
 
through
2018
 remain open to examination by the tax jurisdictions to which the Company is subject.
 
Tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R.
1
), was enacted on
December 22, 2017.
ASC
740,
Accounting for Income Taxes
, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after
December 31, 2017.
Since the Company's federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to
21%
did
not
materially affect the Company's financial statements. Significant provisions  
may
impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of
30%
of adjusted taxable income for levered balance sheets, a limitation on utilization of NOLs generated after tax year
2017
to
80%
of taxable income, the unlimited carryforward of NOLs generated after tax year
2017,
temporary
100%
expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, the Company does
not
anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of its NOL carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from the Company's  current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation
may
have a significant effect on this projection.
v3.19.2
Note 4 - Long-term Debt
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Long-term Debt [Text Block]
4.
Long-Term Debt
 
The following is a description of the Company’s debt as of
June 30, 2019
 and
December 31, 2018
, respectively:
 
 
   
June 30, 2019
   
December 31, 2018
 
Senior secured credit facility
  $
183,000
    $
180,000
 
Real estate lien note
   
3,227
     
3,358
 
     
186,227
     
183,358
 
Less current maturities
   
(274
)    
(267
)
    $
185,953
    $
183,091
 
 
 
Credit Facility
 
The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility.  As of
June 30, 2019
$183.0
  million was outstanding under the credit facility.
 
The credit facility has a maximum commitment of
$300.0
million and availability is subject to a borrowing base. At
June 30, 2019
, the Company had a borrowing base of
$217.5
million. The borrowing base is determined semi-annually by the lenders based upon the Company's reserve reports,
one
of which must be prepared by its independent petroleum engineers and
one
of which
may
be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Company's proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make
one
additional borrowing base redetermination during any
six
-month period between scheduled redeterminations and the Company is able to request
one
redetermination during any
six
-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or the Company must pledge additional oil and gas properties or other assets as collateral. The Company does
not
currently have any substantial unpledged assets and it
may
not
have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause the Company to fail to be in compliance with the financial covenants described below. The Company's borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of
5%
or more of its then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by
5%
or more. The Company's borrowing base can never exceed the
$300.0
million maximum commitment amount.  Outstanding amounts under the credit facility bear interest (a) at any time an event of default exists, at
3%
per annum plus the amounts set forth below, and (b) at all other times, 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) a rate determined by Société Générale as the daily
one
-month LIBOR plus, in each case, (i)
1.5%
-
2.5%,
depending on the utilization of the borrowing base, or (ii) if we elect, LIBOR plus, in each case,
2.5%
-
3.5%
depending on the utilization of the borrowing base. At
June 30, 2019
, the interest rate on the credit facility was approximately
5.7%
assuming LIBOR borrowings.
 
Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is
May 
16,
2021.
Interest is payable quarterly on reference rate advances and
not
less than quarterly on LIBOR advances. The Company is permitted to terminate the credit facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.
 
Each of the Company's subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a
first
priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least
90%
of the PV-
10
of our proven reserves. The Company has also granted our lenders a security interest in our headquarters building.
 
Under the credit facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements.  The Company is required to maintain a current ratio, as defined in the 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.
  The Company is 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 is defined as the ratio of consolidated current assets to consolidated current liabilities.  For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC
815
and ASC
410
-
20
and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC
815
and ASC
410
-
20.
  The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the
four
fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC
718,
ASC
815
and ASC
410
-
20
plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to
$1.0
million of extraordinary expenses in any
12
-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC
815
and ASC
410
-
20.
Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the
four
fiscal quarters ended on the calculation date.  For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the headquarters building and obligations with respect to surety bonds and derivative contracts
.
 
At
June 30, 2019
, the Company was in compliance with all of these financial covenants. As of
June 30, 2019
, the interest coverage ratio was 
8.12
 to
1.00,
the total debt to EBITDAX ratio was 
2.24
 to
1.00,
and our current ratio was 
1.10
to
1.00.
 
The 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;
 
 
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 credit facility also contains certain additional covenants including requirements that:
 
 
100%
of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and
 
 
if the sum of our cash on hand plus liquid investments exceeds
$10.0
million, then the amount in excess of
$10.0
million must be used to pay amounts outstanding under the credit facility.
 
The 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. As of
June 30, 2019
, the Company was in compliance with all of the terms of the credit facility.
 
Real Estate Lien Note
 
The Company has 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 note was modified on
June 20, 2018
to a fixed rate of
4.9%
and is payable in monthly installments of
$35,672.
The maturity date of the note is
July 20, 2023.
As of
June 30, 2019
 and
December 31, 2018
,
$3.2
 million and
$3.4
million, respectively, were outstanding on the note.
v3.19.2
Note 5 - Earnings Per Share
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Earnings Per Share [Text Block]
5.
Earnings per Share
 
The following table sets forth the computation of basic and diluted earnings per share:
 
 
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2019
   
2018
   
2019
   
2018
 
Numerator:
                               
Net income (loss)
  $
11,678
    $
(10,554
)   $
(13,777
)   $
225
 
Denominator:
                               
Denominator for basic earnings per share – weighted-average common shares outstanding
   
166,491
     
165,162
     
165,727
     
164,812
 
Effect of dilutive securities:
                               
Stock options and restricted shares
   
858
     
-
     
-
     
2,903
 
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares
   
167,349
     
165,162
     
165,727
     
167,715
 
                                 
Net income (loss) per common share - basic
  $
0.07
    $
(0.06
)   $
(0.08
)   $
0.00
 
                                 
Net income (loss) per common share - diluted
  $
0.07
    $
(0.06
)   $
(0.08
)   $
0.00
 
 
Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the
three
month period ended
June 30, 2018,  
3.2
million 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
six
month period ended
June 30, 2019, 
869
thousand 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.
 
v3.19.2
Note 6 - Hedging Program and Derivatives
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Derivative Instruments and Hedging Activities Disclosure [Text Block]
6.
  
Hedging Program and Derivatives
 
The derivative contracts the Company utilizes are based on index prices that
may
and often do differ from the actual oil and gas prices realized in our operations.  The Company's 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
June 30, 2019
:
 
 
   
Oil - WTI
 
Contract Periods
 
Daily Volume (Bbl)
   
Swap Price (per Bbl)
 
Fixed Swaps
               
2019 July - December
   
4,097
    $
56.85
 
2020 January - December
   
3,023
    $
55.25
 
2021 January - December
   
2,051
    $
59.78
 
                 
Basis Swaps
               
2019 July - December
   
4,000
    $
2.98
 
2020 January - December
   
4,000
    $
2.98
 
 
The following table illustrates the impact of derivative contracts on the Company’s balance sheet:
 
Fair Value of Derivative Contracts as of June 30, 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
  $
517
 
Derivatives – current
  $
7,785
 
Commodity price derivatives
 
Derivatives – long-term
   
4,394
 
Derivatives – long-term
   
3,529
 
   
 
  $
4,911
 
 
  $
11,314
 
 
 
Fair Value of Derivative Contracts as of December 31, 2018
 
   
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
  $
9,602
 
Derivatives – current
  $
616
 
Commodity price derivatives
 
Derivatives – long-term
   
10,527
 
Derivatives – long-term
   
4,434
 
   
 
  $
20,129
 
 
  $
5,050
 
 
v3.19.2
Note 7 - Financial Instruments
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Fair Value Disclosures [Text Block]
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. The Company’s 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. The Company is 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 the Company’s assets and liabilities measured at fair value on a recurring basis as of
June 30, 2019
 and
December 31, 2018
, and indicate the fair value hierarchy of the valuation techniques utilized by the Company 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 June 30, 2019
 
Assets:
                               
NYMEX fixed price derivative contracts
  $
    $
4,911
    $
    $
4,911
 
Total Assets
  $
    $
4,911
    $
    $
4,911
 
 
                               
Liabilities:                                
NYMEX fixed price derivative contracts
  $
    $
3,394
    $
    $
3,394
 
NYMEX basis differential swaps
   
     
     
7,920
     
7,920
 
Total Liabilities
  $
    $
3,394
    $
7,920
    $
11,314
 
 
   
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, 2018
 
Assets:
                               
NYMEX fixed price derivative contracts
  $
    $
18,172
    $
    $
18,172
 
NYMEX basis differential swap contracts
   
     
     
1,957
     
1,957
 
Total Assets
  $
    $
18,172
    $
1,957
    $
20,129
 
                                 
Liabilities:
                               
NYMEX fixed price derivative contracts
  $
    $
    $
    $
 
NYMEX basis differential swaps
   
     
     
5,050
     
5,050
 
Total Liabilities
  $
    $
-
    $
5,050
    $
5,050
 
 
The Company’s derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of
June 30, 2019
 and  
December 31, 2018
. Under fixed price swaps, the Company receives a fixed price for its production and pays a variable market price to the contract counter-party. Under a basis differential swap, if the market price is above the fixed price, the Company pays the counter-party, if the market price is below the fixed price, the counter-party pays the Company. The NYMEX-based fixed price derivative swaps and basis swaps 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, the Company enters the various inputs into a model and compares 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 the Company's recurring fair value measurements using significant unobservable inputs (Level
3
inputs) for the
six
months ended
June 30, 2019.
 
Unobservable inputs at January 1, 2019
  $
(3,093
)
Changes in market value
   
(5,470
)
Settlements during the period
   
643
 
Unobservable inputs at June 30, 2019
  $
(7,920
)
 
Nonrecurring Fair Value Measurements
 
The Company follows the provisions of ASC
820
-
10
for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC
820
-
10
applies to certain nonfinancial 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.
 
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 the Company's 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.
v3.19.2
Note 8 - Leases
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Lessee, Operating Leases [Text Block]
8.
Leases
 
We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do
not
have any finance leases. We capitalize our operating leases on our consolidated balance sheet through a Right of Use ("ROU")  asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of 
one
year or less are
not
capitalized but are disclosed below. 
 
Our operating leases are reflected as operating lease ROU assets, operating lease liability - current and long-term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement and initial direct cost incurred less any lease incentives. Lease expense for operating leases is recognized on a straight-line basis over the lease term.
 
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 compressors and coolers 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 compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do
not
exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with
third
parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing
thirty
days' notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or
not
extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.
 
Discount Rate
 
Our leases typically do
not
provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.
 
Practical Expedients and Accounting Policy Elections
 
Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election
not
to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of
12
months or less and does
not
include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has
not
changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred.
None
of our current leases contain variable payments.  Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.
 
The components of our total lease expense for the
three
and
six
months ended
June 30, 2019
, the majority of which is included in lease operating expense, are as follows:
 
   
Three Months Ended
June 30, 2019
   
Six Months Ended June 30, 2019
 
Operating lease cost
  $
123
    $
240
 
Short-term lease expense (1)
  $
475
    $
938
 
Total lease expense
  $
598
    $
1,178
 
                 
Short-term lease costs (2)
  $
2,254
    $
3,771
 
 
 
(
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:
 
   
June 30, 2019
 
Operating lease ROU assets
  $
518
 
Operating lease liability - current
  $
284
 
Operating lease liabilities - long-term
  $
229
 
 
Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:
 
   
June 30, 2019
 
Weighted Average Remaining Lease Term (in years)
   
5.42
 
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 2019
  $
298
 
2020
   
88
 
2021
   
49
 
2022
   
43
 
2023
   
39
 
Thereafter
   
99
 
Total lease payments
   
616
 
Less imputed interest
   
(103
)
Total lease liability
  $
513
 
 
Supplemental cash flow information related to our operating leases is included in the table below:
 
   
Three Months Ended
June 30, 2019
   
Six Months Ended June 30, 2019
 
Cash paid for amounts included in the measurement of lease liabilities
  $
123
    $
240
 
ROU assets added in exchange for lease obligations (since adoption)
  $
48
    $
735
 
v3.19.2
Note 9 - Commitments and Contingencies
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Commitments and Contingencies Disclosure [Text Block]
9.
Commitments and Contingencies
 
From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At
June 30, 2019
, the Company was
not
involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its financial position or results of operations.
v3.19.2
Note 10 - Subsequent Events
6 Months Ended
Jun. 30, 2019
Notes to Financial Statements  
Subsequent Events [Text Block]
10.
 Subsequent Event
 
Subsequent to
June 30, 2019,
the Company entered into the following derivative contracts:
 
   
Oil - WTI
 
Contract Periods
 
Daily Volume (Bbl)
   
Swap Price
(per Bbl)
 
Fixed Swaps
               
2019 August - December
   
1,438
    $
56.02
 
2020 January - December
   
754
    $
55.16
 
2021 January - December
   
756
    $
52.50
 
 
 
 
 
v3.19.2
Significant Accounting Policies (Policies)
6 Months Ended
Jun. 30, 2019
Accounting Policies [Abstract]  
Reclassification, Policy [Policy Text Block]
Reclassifications
 
Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications had
no
effect on the Company’s previously reported results of operations.
Consolidation, Policy [Policy Text Block]
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 [Policy Text Block]
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 the Company or its 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, Policy [Policy Text Block]
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.
New Accounting Pronouncements, Policy [Policy Text Block]
Recently Adopted Lease Accounting Standard
 
In
February 2016,
an accounting standards update was issued that requires an entity to recognize a right-of-use (“ROU”) asset and lease liability for certain leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.
 
The new standard was effective for us in the
first
quarter of 
2019
 and we adopted the new standard using a modified retrospective approach, with the date of initial application on
January 1, 2019.
Consequently, upon transition, we recognized an ROU asset (or operating lease right-of-use asset) and a lease liability with
no
retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to:
 
 
Not
apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of
12
months or less);
 
Not
reassess whether a contract contains a lease, lease classification and initial direct costs; and
 
Not
reassess certain land easements in existence prior to
January 1, 2019.
 
The impact of adoption of this new standard on our balance sheet was as follows:
 
   
January 1, 2019
 
Operating lease ROU asset
  $
687
 
Operating lease liability - current
  $
(108
)
Operating lease liability - long-term
  $
(579
)
 
Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are
not
within the scope of the standards update. For more information, see Note
8.
Share-based Payment Arrangement [Policy Text Block]
Stock-Based Compensation and Option Plans
 
Stock Options
 
The Company currently utilizes 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 the Company’s stock-based compensation expense related to stock options for the periods presented: 
 
 
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
74
    $
574
    $
225
    $
914
 
 
The following table summarizes the Company’s stock option activity for the
six
months ended
June 30, 2019
:
 
   
Number of Shares
   
Weighted Average Option Exercise Price Per Share
   
Weighted Average Grant Date Fair Value Per Share
 
Outstanding, December 31, 2018
   
7,549
    $
2.37
    $
1.68
 
Granted
   
     
     
 
Exercised
   
(469
)   $
0.98
    $
0.68
 
Forfeited
   
(572
)   $
3.00
    $
2.12
 
Outstanding, June 30, 2019
   
6,508
    $
2.41
    $
1.71
 
    
As of
June 30, 2019
, there was approximately
$0.3
 million of unamortized compensation expense related to outstanding stock options that will be recognized from 
2019
 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 the Company 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 the Company’s restricted stock activity for the
six
months ended
June 30, 2019
 
 
   
Number of Shares (thousands)
   
Weighted Average Grant Date Fair Value Per Share
 
Unvested, December 31, 2018
   
827
    $
2.15
 
Granted
   
1,315
    $
1.34
 
Vested/Released
   
(228
)   $
2.22
 
Forfeited
   
    $
-
 
Unvested, June 30, 2019
   
1,914
    $
1.59
 
 
The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented: 
 
 
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
277
    $
221
    $
420
    $
468
 
 
As of
June 30, 2019
, there was approximately
$2.5
 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized from 
2019
 through
2022.
 
Performance Based Restricted Stock
 
The Company issues 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 the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of the Company’s 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, 2018
   
405
    $
2.37
 
Granted
   
803
    $
1.34
 
Vested/Released
   
    $
-
 
Forfeited
   
    $
-
 
Unvested, June 30, 2019
   
1,208
    $
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 the Company's 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 the Company’s stock-based compensation expense related to performance based restricted stock for the periods presented: 
 
 
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
170
    $
84
    $
249
    $
84
 
 
As of
June 30, 2019
, there was approximately
$1.6
 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 
2019
 through
2022.
Oil and Gas Properties Policy [Policy Text Block]
Oil and Gas Properties
 
The Company follows 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At
June 30, 2019
 and
2018
, our net capitalized costs of oil and gas properties did
not
exceed the cost ceiling of our estimated proved reserves.
 
In
May 2019,
the Company closed on the sale of its non-operated assets in the Bakken. Proceeds from the sale of approximately
$15.8
million were used to reduce outstanding indebtedness under its credit facility. In accordance with full cost accounting rules, the sale was
not
deemed to be singnificant,; therefore,
no
gain or loss was recorded and the proceeds were credited to the full cost pool.
Asset Retirement Obligation and Environmental Cost [Policy Text Block]
Restoration, Removal and Environmental Liabilities
 
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and
may
require the Company 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.
 
The Company accounts 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 the Company’s future site restoration obligation transactions for the
six
months ended
June 30, 2019
 and the year ended
December 31, 2018
 
 
   
June 30, 2019
   
December 31, 2018
 
Beginning future site restoration obligation
  $
7,492
    $
8,775
 
New wells placed on production and other
   
80
     
612
 
Deletions related to property disposals and plugging costs
   
(487
)    
(2,270
)
Accretion expense
   
220
     
516
 
Revisions and other
   
458
     
(141
)
Ending future site restoration obligation
  $
7,763
    $
7,492
 
v3.19.2
Note 1 - Basis of Presentation (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]
   
January 1, 2019
 
Operating lease ROU asset
  $
687
 
Operating lease liability - current
  $
(108
)
Operating lease liability - long-term
  $
(579
)
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Table Text Block]
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
74
    $
574
    $
225
    $
914
 
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
277
    $
221
    $
420
    $
468
 
Three Months Ended
   
Six Months Ended
 
June 30,
   
June 30,
 
2019
   
2018
   
2019
   
2018
 
$
170
    $
84
    $
249
    $
84
 
Share-based Payment Arrangement, Option, Activity [Table Text Block]
   
Number of Shares
   
Weighted Average Option Exercise Price Per Share
   
Weighted Average Grant Date Fair Value Per Share
 
Outstanding, December 31, 2018
   
7,549
    $
2.37
    $
1.68
 
Granted
   
     
     
 
Exercised
   
(469
)   $
0.98
    $
0.68
 
Forfeited
   
(572
)   $
3.00
    $
2.12
 
Outstanding, June 30, 2019
   
6,508
    $
2.41
    $
1.71
 
Nonvested Restricted Stock Shares Activity [Table Text Block]
   
Number of Shares (thousands)
   
Weighted Average Grant Date Fair Value Per Share
 
Unvested, December 31, 2018
   
827
    $
2.15
 
Granted
   
1,315
    $
1.34
 
Vested/Released
   
(228
)   $
2.22
 
Forfeited
   
    $
-
 
Unvested, June 30, 2019
   
1,914
    $
1.59
 
Schedule of Nonvested Performance-based Units Activity [Table Text Block]
   
Number of Shares (thousands)
   
Weighted Average Grant Date Fair Value Per Share
 
Unvested, December 31, 2018
   
405
    $
2.37
 
Granted
   
803
    $
1.34
 
Vested/Released
   
    $
-
 
Forfeited
   
    $
-
 
Unvested, June 30, 2019
   
1,208
    $
1.69
 
Schedule of Change in Asset Retirement Obligation [Table Text Block]
   
June 30, 2019
   
December 31, 2018
 
Beginning future site restoration obligation
  $
7,492
    $
8,775
 
New wells placed on production and other
   
80
     
612
 
Deletions related to property disposals and plugging costs
   
(487
)    
(2,270
)
Accretion expense
   
220
     
516
 
Revisions and other
   
458
     
(141
)
Ending future site restoration obligation
  $
7,763
    $
7,492
 
v3.19.2
Note 2 - Revenue From Contracts With Customers (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Disaggregation of Revenue [Table Text Block]
   
Three Months Ended June 30,
 
   
2019
   
2018
 
   
Oil
   
Gas
   
NGL
   
Oil
   
Gas
   
NGL
 
Operating Regions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian/Delaware Basin
  $
15,562
    $
24
    $
27
    $
9,664
    $
609
    $
613
 
Rocky Mountain
  $
17,567
    $
208
    $
238
    $
15,479
    $
674
    $
1,180
 
South Texas
  $
1,017
    $
176
    $
-
    $
2,329
    $
325
    $
42
 
   
Six Months Ended June 30,
 
   
2019
   
2018
 
   
Oil
   
Gas
   
NGL
   
Oil
   
Gas
   
NGL
 
Operating Regions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permian/Delaware Basin
  $
24,626
    $
311
    $
340
    $
24,039
    $
1,528
    $
1,411
 
Rocky Mountain
  $
39,367
    $
1,162
    $
978
    $
34,719
    $
1,802
    $
2,583
 
South Texas
  $
2,134
    $
408
    $
3
    $
4,708
    $
655
    $
64
 
v3.19.2
Note 4 - Long-term Debt (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Schedule of Long-term Debt Instruments [Table Text Block]
   
June 30, 2019
   
December 31, 2018
 
Senior secured credit facility
  $
183,000
    $
180,000
 
Real estate lien note
   
3,227
     
3,358
 
     
186,227
     
183,358
 
Less current maturities
   
(274
)    
(267
)
    $
185,953
    $
183,091
 
v3.19.2
Note 5 - Earnings Per Share (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2019
   
2018
   
2019
   
2018
 
Numerator:
                               
Net income (loss)
  $
11,678
    $
(10,554
)   $
(13,777
)   $
225
 
Denominator:
                               
Denominator for basic earnings per share – weighted-average common shares outstanding
   
166,491
     
165,162
     
165,727
     
164,812
 
Effect of dilutive securities:
                               
Stock options and restricted shares
   
858
     
-
     
-
     
2,903
 
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares
   
167,349
     
165,162
     
165,727
     
167,715
 
                                 
Net income (loss) per common share - basic
  $
0.07
    $
(0.06
)   $
(0.08
)   $
0.00
 
                                 
Net income (loss) per common share - diluted
  $
0.07
    $
(0.06
)   $
(0.08
)   $
0.00
 
v3.19.2
Note 6 - Hedging Program and Derivatives (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Schedule of Derivative Instruments [Table Text Block]
   
Oil - WTI
 
Contract Periods
 
Daily Volume (Bbl)
   
Swap Price (per Bbl)
 
Fixed Swaps
               
2019 July - December
   
4,097
    $
56.85
 
2020 January - December
   
3,023
    $
55.25
 
2021 January - December
   
2,051
    $
59.78
 
                 
Basis Swaps
               
2019 July - December
   
4,000
    $
2.98
 
2020 January - December
   
4,000
    $
2.98
 
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]
Fair Value of Derivative Contracts as of June 30, 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
  $
517
 
Derivatives – current
  $
7,785
 
Commodity price derivatives
 
Derivatives – long-term
   
4,394
 
Derivatives – long-term
   
3,529
 
   
 
  $
4,911
 
 
  $
11,314
 
Fair Value of Derivative Contracts as of December 31, 2018
 
   
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
  $
9,602
 
Derivatives – current
  $
616
 
Commodity price derivatives
 
Derivatives – long-term
   
10,527
 
Derivatives – long-term
   
4,434
 
   
 
  $
20,129
 
 
  $
5,050
 
v3.19.2
Note 7 - Financial Instruments (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]
   
Quoted Prices in Active Markets for Identical Assets (Level 1)
   
Significant Other Observable Inputs (Level 2)
   
Significant Unobservable Inputs (Level 3)
   
Balance as of June 30, 2019
 
Assets:
                               
NYMEX fixed price derivative contracts
  $
    $
4,911
    $
    $
4,911
 
Total Assets
  $
    $
4,911
    $
    $
4,911
 
 
                               
Liabilities:                                
NYMEX fixed price derivative contracts
  $
    $
3,394
    $
    $
3,394
 
NYMEX basis differential swaps
   
     
     
7,920
     
7,920
 
Total Liabilities
  $
    $
3,394
    $
7,920
    $
11,314
 
   
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, 2018
 
Assets:
                               
NYMEX fixed price derivative contracts
  $
    $
18,172
    $
    $
18,172
 
NYMEX basis differential swap contracts
   
     
     
1,957
     
1,957
 
Total Assets
  $
    $
18,172
    $
1,957
    $
20,129
 
                                 
Liabilities:
                               
NYMEX fixed price derivative contracts
  $
    $
    $
    $
 
NYMEX basis differential swaps
   
     
     
5,050
     
5,050
 
Total Liabilities
  $
    $
-
    $
5,050
    $
5,050
 
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]
Unobservable inputs at January 1, 2019
  $
(3,093
)
Changes in market value
   
(5,470
)
Settlements during the period
   
643
 
Unobservable inputs at June 30, 2019
  $
(7,920
)
v3.19.2
Note 8 - Leases (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Lease, Cost [Table Text Block]
   
Three Months Ended
June 30, 2019
   
Six Months Ended June 30, 2019
 
Operating lease cost
  $
123
    $
240
 
Short-term lease expense (1)
  $
475
    $
938
 
Total lease expense
  $
598
    $
1,178
 
                 
Short-term lease costs (2)
  $
2,254
    $
3,771
 
   
June 30, 2019
 
Weighted Average Remaining Lease Term (in years)
   
5.42
 
Weighted Average Discount Rate
   
6
%
   
Three Months Ended
June 30, 2019
   
Six Months Ended June 30, 2019
 
Cash paid for amounts included in the measurement of lease liabilities
  $
123
    $
240
 
ROU assets added in exchange for lease obligations (since adoption)
  $
48
    $
735
 
Schedule of Operating Leased Assets [Table Text Block]
   
June 30, 2019
 
Operating lease ROU assets
  $
518
 
Operating lease liability - current
  $
284
 
Operating lease liabilities - long-term
  $
229
 
Lessee, Operating Lease, Liability, Maturity [Table Text Block]
   
Operating Leases
 
Remainder of 2019
  $
298
 
2020
   
88
 
2021
   
49
 
2022
   
43
 
2023
   
39
 
Thereafter
   
99
 
Total lease payments
   
616
 
Less imputed interest
   
(103
)
Total lease liability
  $
513
 
v3.19.2
Note 10 - Subsequent Events (Tables)
6 Months Ended
Jun. 30, 2019
Notes Tables  
Subsequent Events [Table Text Block]
   
Oil - WTI
 
Contract Periods
 
Daily Volume (Bbl)
   
Swap Price
(per Bbl)
 
Fixed Swaps
               
2019 August - December
   
1,438
    $
56.02
 
2020 January - December
   
754
    $
55.16
 
2021 January - December
   
756
    $
52.50
 
v3.19.2
Note 1 - Basis of Presentation (Details Textual) - USD ($)
$ in Thousands
1 Months Ended 6 Months Ended
Apr. 01, 2018
May 31, 2019
Jun. 30, 2019
Jun. 30, 2018
Discount Rate Used in Future Net Cash Flows Relating to Proved Oil and Gas Reserves     10.00%  
Proceeds from Sale of Oil and Gas Property and Equipment     $ 16,805 $ 82
Non-operated Assets in the Balkans [Member]        
Proceeds from Sale of Oil and Gas Property and Equipment   $ 15,800    
Share-based Payment Arrangement, Option [Member]        
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total     300  
Restricted Stock [Member]        
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total     2,500  
Performance Shares [Member]        
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total     $ 1,600  
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period 3 years      
Performance Shares [Member] | Minimum [Member]        
Share-based Compensation Arrangement by Share-based Payment, Award, Percentage of Performance Shares that are Received 0.00%      
Performance Shares [Member] | Maximum [Member]        
Share-based Compensation Arrangement by Share-based Payment, Award, Percentage of Performance Shares that are Received 200.00%      
v3.19.2
Note 1 - Basis of Presentation - Impact of Adoption (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Jan. 01, 2019
Dec. 31, 2018
Operating lease ROU asset $ 518  
Operating lease liability - current (284)  
Operating lease liability - long-term $ (229)  
Accounting Standards Update 2016-02 [Member]      
Operating lease ROU asset   $ 687  
Operating lease liability - current   (108)  
Operating lease liability - long-term   $ (579)  
v3.19.2
Note 1 - Basis of Presentation - Stock-based Compensation Expense (Details) - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Share-based Payment Arrangement, Option [Member]        
Stock-based compensation expense $ 74 $ 574 $ 225 $ 914
Restricted Stock [Member]        
Stock-based compensation expense 277 221 420 468
Performance Shares [Member]        
Stock-based compensation expense $ 170 $ 84 $ 249 $ 84
v3.19.2
Note 1 - Basis of Presentation - Stock Option Activity (Details) - Share-based Payment Arrangement, Option [Member]
shares in Thousands
6 Months Ended
Jun. 30, 2019
$ / shares
shares
Outstanding (in shares) | shares 7,549
Outstanding, weighted average option exercise price (in dollars per share) $ 2.37
Outstanding, weighted average grant date fair value (in dollars per share) $ 1.68
Granted (in shares) | shares
Granted, weighted average option exercise price (in dollars per share)
Granted, weighted average grant date fair value (in dollars per share)
Exercised (in shares) | shares (469)
Exercised, weighted average option exercise price (in dollars per share) $ 0.98
Exercised, weighted average grant date fair value (in dollars per share) $ 0.68
Forfeited (in shares) | shares (572)
Forfeited, weighted average option exercise price (in dollars per share) $ 3
Forfeited, weighted average grant date fair value (in dollars per share) $ 2.12
Outstanding (in shares) | shares 6,508
Outstanding, weighted average option exercise price (in dollars per share) $ 2.41
Outstanding, weighted average grant date fair value (in dollars per share) $ 1.71
v3.19.2
Note 1 - Basis of Presentation - Restricted Stock Activity (Details) - Restricted Stock [Member]
shares in Thousands
6 Months Ended
Jun. 30, 2019
$ / shares
shares
Unvested (in shares) | shares 827
Unvested, weighted average grant date fair value (in dollars per share) | $ / shares $ 2.15
Granted (in shares) | shares 1,315
Granted, weighted average grant date fair value (in dollars per share) | $ / shares $ 1.34
Vested/Released (in shares) | shares (228)
Vested/Released, weighted average grant date fair value (in dollars per share) | $ / shares $ 2.22
Forfeited (in shares) | shares
Forfeited, weighted average grant date fair value (in dollars per share) | $ / shares
Unvested (in shares) | shares 1,914
Unvested, weighted average grant date fair value (in dollars per share) | $ / shares $ 1.59
v3.19.2
Note 1 - Basis of Presentation - Performance Based Restricted Stock Activity (Details) - Performance Shares [Member]
shares in Thousands
6 Months Ended
Jun. 30, 2019
$ / shares
shares
Unvested (in shares) | shares 405
Unvested, weighted average grant date fair value (in dollars per share) | $ / shares $ 2.37
Granted (in shares) | shares 803
Granted, weighted average option exercise price (in dollars per share) | $ / shares $ 1.34
Vested/Released (in shares) | shares
Vested/Released, weighted average grant date fair value (in dollars per share) | $ / shares
Forfeited (in shares) | shares
Forfeited, weighted average option exercise price (in dollars per share) | $ / shares
Unvested (in shares) | shares 1,208
Unvested, weighted average grant date fair value (in dollars per share) | $ / shares $ 1.69
v3.19.2
Note 1 - Basis of Presentation - Future Site Restoration Obligation (Details) - USD ($)
$ in Thousands
6 Months Ended 12 Months Ended
Jun. 30, 2019
Dec. 31, 2018
Beginning future site restoration obligation $ 7,492 $ 8,775
New wells placed on production and other 80 612
Deletions related to property disposals and plugging costs (487) (2,270)
Accretion expense 220 516
Revisions and other 458 (141)
Ending future site restoration obligation $ 7,763 $ 7,492
v3.19.2
Note 2 - Revenue From Contracts With Customers (Details Textual) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Accounts Receivable, before Allowance for Credit Loss, Current $ 17,023 $ 21,991
v3.19.2
Note 2 - Revenue From Contracts With Customers - Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Oil Revenues [Member]        
Revenue $ 34,146 $ 27,472 $ 66,127 $ 63,466
Gas Revenues [Member]        
Revenue 408 1,608 1,881 3,985
Natural Gas Liquids Revenues [Member]        
Revenue 265 1,835 1,321 4,058
Permian / Delaware Basin [Member] | Oil Revenues [Member]        
Revenue 15,562 9,664 24,626 24,039
Permian / Delaware Basin [Member] | Gas Revenues [Member]        
Revenue 24 609 311 1,528
Permian / Delaware Basin [Member] | Natural Gas Liquids Revenues [Member]        
Revenue 27 613 340 1,411
Rocky Mountain [Member] | Oil Revenues [Member]        
Revenue 17,567 15,479 39,367 34,719
Rocky Mountain [Member] | Gas Revenues [Member]        
Revenue 208 674 1,162 1,802
Rocky Mountain [Member] | Natural Gas Liquids Revenues [Member]        
Revenue 238 1,180 978 2,583
South Texas [Member] | Oil Revenues [Member]        
Revenue 1,017 2,329 2,134 4,708
South Texas [Member] | Gas Revenues [Member]        
Revenue 176 325 408 655
South Texas [Member] | Natural Gas Liquids Revenues [Member]        
Revenue $ 42 $ 3 $ 64
v3.19.2
Note 3 - Income Taxes (Details Textual) - USD ($)
$ in Thousands
3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Dec. 31, 2018
Income Tax Expense (Benefit), Total $ 0 $ 0 $ 0 $ 0  
Deferred Tax Assets, Valuation Allowance, Total         $ 67,300
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued, Total $ 0   $ 0    
Open Tax Year     2013 2014 2015 2016 2017 2018    
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent         21.00%
Pre 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]          
Operating Loss Carryforwards, Total         $ 245,200
Tax Year 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]          
Operating Loss Carryforwards, Total         $ 46,800
Earliest Tax Year [Member]          
Operating Loss Carryforwards, Expiration Date         Jan. 01, 2023
Latest Tax Year [Member]          
Operating Loss Carryforwards, Expiration Date         Dec. 31, 2037
v3.19.2
Note 4 - Long-term Debt (Details Textual)
6 Months Ended
Jun. 30, 2019
USD ($)
Dec. 31, 2018
USD ($)
Financial Covenants, Minimum Current Ratio 1  
Financial Covenants, Interest Coverage Ratio 2.5  
Financial Covenants, Total Debt to EBITDAX Ratio 3.5  
Debt Instrument Covenants, Extraordinary Expenses Included in Determining EBITDAX $ 1,000,000  
Interest Coverage Ratio 8.12  
Total Debt to EBITDAX Ratio 2.24  
Current Ratio 1.1  
Line of Credit Covenant, Percentage of Net Proceeds to be Used for Repayment 100.00%  
Line of Credit Covenant, Cash and Liquid Investments Triggering Credit Repayment $ 10,000,000  
Long-term Debt, Total 186,227,000 $ 183,358,000
Line of Credit [Member]    
Long-term Line of Credit, Total 183,000,000  
Line of Credit Facility, Maximum Borrowing Capacity 300,000,000  
Line of Credit Facility, Current Borrowing Capacity $ 217,500,000  
Line of Credit, Market Value of Property, Minimum Percentage 5.00%  
Line of Credit, Reduced Collateral Value, Minimum Percentage 5.00%  
Line of Credit, Default, Minimum Interest Rate 3.00%  
Debt Instrument, Spread on Elected Variable Rate 0.50%  
Line of Credit Facility, Interest Rate at Period End 5.70%  
Debt Instrument, Maturity Date May 16, 2021  
Debt Instrument, Collateral Eligible, Minimum Percent of PV-10 Required 90.00%  
Long-term Debt, Total $ 183,000,000 180,000,000
Line of Credit [Member] | Minimum [Member]    
Debt Instrument, Spread on Elected Variable Rate 2.50%  
Debt Instrument, Basis Spread on Variable Rate 1.50%  
Line of Credit [Member] | Maximum [Member]    
Debt Instrument, Spread on Elected Variable Rate 3.50%  
Debt Instrument, Basis Spread on Variable Rate 2.50%  
Construction Loans [Member]    
Debt Instrument, Interest Rate, Stated Percentage 4.90%  
Debt Instrument, Periodic Payment, Total $ 35,672  
Long-term Debt, Total $ 3,200,000 $ 3,400,000
v3.19.2
Note 4 - Long-term Debt - Debt (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Long-term debt $ 186,227 $ 183,358
Long-term debt 186,227 183,358
Less current maturities (274) (267)
Long-term debt, noncurrent 185,953 183,091
Line of Credit [Member]    
Long-term debt 183,000 180,000
Long-term debt 183,000 180,000
Mortgages [Member]    
Long-term debt 3,227 3,358
Long-term debt $ 3,227 $ 3,358
v3.19.2
Note 5 - Earnings Per Share (Details Textual) - shares
shares in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2018
Jun. 30, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount 3,200 869
v3.19.2
Note 5 - Earnings Per Share - Computation of Basic and Diluted Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
Jun. 30, 2018
Jun. 30, 2019
Jun. 30, 2018
Net (loss) income $ 11,678 $ (10,554) $ (13,777) $ 225
Basic (in shares) 166,491 165,162 165,727 164,812
Stock options and restricted shares (in shares) 858 2,903
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares (in shares) 167,349 165,162 165,727 167,715
Net income (loss) per common share - basic (in dollars per share) $ 0.07 $ (0.06) $ (0.08) $ 0
Net income (loss) per common share - diluted (in dollars per share) $ 0.07 $ (0.06) $ (0.08) $ 0
v3.19.2
Note 6 - Hedging Program and Derivatives - Summary Position of Derivative Contracts (Details) - Oil - WTI [Member]
6 Months Ended
Jun. 30, 2019
bbl
Fixed Swap, Contract Period 2018 April - December [Member]  
Daily volume (Barrel of Oil) 4,097
Swap price 56.85
Fixed Swap, Contract Period 2019 January - December [Member]  
Daily volume (Barrel of Oil) 3,023
Swap price 55.25
Fixed Swap, Contract Period 2020 January - December [Member]  
Daily volume (Barrel of Oil) 2,051
Swap price 59.78
Basis Swap, Contract Period 2019 April - December [Member]  
Daily volume (Barrel of Oil) 4,000
Swap price 2.98
Basis Swap, Contract Period 2020 January - December [Member]  
Daily volume (Barrel of Oil) 4,000
Swap price 2.98
v3.19.2
Note 6 - Hedging Program and Derivatives - Impact of Derivative Contracts on Balance Sheet (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Derivative asset, current $ 517 $ 9,602
Derivative liability, current 7,785 616
Derivative asset, long-term 4,394 10,527
Derivative asset 4,911 20,129
Derivative liability 11,314 5,050
Commodity Contract [Member] | Derivative Assets Current [Member]    
Derivative asset, current 517 9,602
Commodity Contract [Member] | Derivative Liabilities Current [Member]    
Derivative liability, current 7,785 616
Commodity Contract [Member] | Derivative Assets Noncurrent [Member]    
Derivative asset, long-term 4,394 10,527
Commodity Contract [Member] | Derivative Liabilities Noncurrent [Member]    
Derivative liability, long-term $ 3,529 $ 4,434
v3.19.2
Note 7 - Financial Instruments - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Derivative assets $ 4,911 $ 20,129
Derivative liabilities 11,314 5,050
Fair Value, Recurring [Member]    
Derivative assets 4,911 20,129
Derivative liabilities 11,314 5,050
Fair Value, Recurring [Member] | Fixed Price Derivative Contracts [Member]    
Derivative assets 4,911 18,172
Derivative liabilities 3,394
Fair Value, Recurring [Member] | Basis Differential Swap [Member]    
Derivative assets   1,957
Derivative liabilities 7,920 5,050
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]    
Derivative assets
Derivative liabilities
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Price Derivative Contracts [Member]    
Derivative assets
Derivative liabilities
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Basis Differential Swap [Member]    
Derivative assets  
Derivative liabilities
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]    
Derivative assets 4,911 18,172
Derivative liabilities 3,394
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Price Derivative Contracts [Member]    
Derivative assets 4,911 18,172
Derivative liabilities 3,394
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Basis Differential Swap [Member]    
Derivative assets  
Derivative liabilities
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]    
Derivative assets 1,957
Derivative liabilities 7,920 5,050
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Price Derivative Contracts [Member]    
Derivative assets
Derivative liabilities
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Basis Differential Swap [Member]    
Derivative assets   1,957
Derivative liabilities $ 7,920 $ 5,050
v3.19.2
Note 7 - Financial Instruments - Recurring Fair Value Measurements Using Significant Unobservable Inputs (Details) - Fair Value, Inputs, Level 3 [Member]
$ in Thousands
6 Months Ended
Jun. 30, 2019
USD ($)
Unobservable inputs at January 1, 2019 $ (3,093)
Changes in market value (5,470)
Settlements during the period 643
Unobservable inputs at June 30, 2019 $ (7,920)
v3.19.2
Note 8 - Leases (Details Textual)
Jun. 30, 2019
Lease for Residence in North Dakota [Member]  
Lessee, Operating Lease, Term of Contract 5 years
v3.19.2
Note 8 - Leases - Total Lease Expense (Details)
$ in Thousands
3 Months Ended 6 Months Ended
Jun. 30, 2019
USD ($)
Jun. 30, 2019
USD ($)
Operating lease cost $ 123 $ 240
Short-term lease expense 475 [1] 938 [1]
Total lease expense $ 598 $ 1,178
Weighted Average Remaining Lease Term (in years) (Year) 5 years 153 days 5 years 153 days
Weighted Average Discount Rate 6.00% 6.00%
Cash paid for amounts included in the measurement of lease liabilities $ 123 $ 240
ROU assets added in exchange for lease obligations (since adoption) 48 735
Drilling Rig [Member]    
Short-term lease expense $ 2,254 [2] $ 3,771 [2]
[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.
v3.19.2
Note 8 - Leases - Balance Sheet Information (Details) - USD ($)
$ in Thousands
Jun. 30, 2019
Dec. 31, 2018
Operating lease ROU asset $ 518
Operating lease liability - current 284
Operating lease liabilities - long-term $ 229
v3.19.2
Note 8 - Leases - Lease Liabilities Maturity (Details)
$ in Thousands
Jun. 30, 2019
USD ($)
Remainder of 2019 $ 298
2020 88
2021 49
2022 43
2023 39
Thereafter 99
Total lease payments 616
Less imputed interest (103)
Total lease liability $ 513
v3.19.2
Note 10 - Subsequent Event - Derivative Contracts (Details) - Oil - WTI [Member]
1 Months Ended 6 Months Ended
Aug. 08, 2019
bbl
Jun. 30, 2019
bbl
Fixed Swap, Contract Period 2020 January - December [Member]    
Daily volume (Barrel of Oil)   2,051
Swap price   59.78
Subsequent Event [Member] | Fixed Swap, Contract Period 2019 August - December [Member]    
Daily volume (Barrel of Oil) 1,438  
Swap price 56.02  
Subsequent Event [Member] | Fixed Swap, Contract Period 2020 January - December [Member]    
Daily volume (Barrel of Oil) 754  
Swap price 55.16  
Subsequent Event [Member] | Fixed Swap, Contract Period 2021 January - December [Member]    
Daily volume (Barrel of Oil) 756  
Swap price 52.5