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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
_________________________________
FORM 10-Q
_________________________________
 
  ☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2020
   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from ____________ to____________
 
Commission File No. 001-33999
NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware 95-3848122
(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer Identification No.)
601 Carlson Pkwy – Suite 990
Minnetonka, Minnesota 55305
(Address of Principal Executive Offices)
(952) 476-9800
(Registrant’s Telephone Number)
N/A
(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(s) Name of each exchange on which registered
Common Stock, par value $0.001 NOG
NYSE American
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   No

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted 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 such files).  Yes   No

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

Smaller Reporting Company  ☐
Emerging Growth Company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 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

As of May 7, 2020, there were 405,793,741 shares of our common stock, par value $0.001, outstanding.


GLOSSARY OF TERMS

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

Bbl.”  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

Boe.”  A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.

Boepd. Boe per day.

Btu or British Thermal Unit.”  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MBbl.”  One thousand barrels of crude oil, condensate or NGLs.

MBoe.”  One thousand Boe.

Mcf.”  One thousand cubic feet of natural gas.

MMBbl.”  One million barrels of crude oil, condensate or NGLs.

MMBoe.”  One million Boe.

MMBtu.”  One million British Thermal Units.

MMcf.”  One million cubic feet of natural gas.

NGLs.”  Natural gas liquids.  Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Terms used to describe our interests in wells and acreage:

Basin.”  A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Completion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.

Conventional play.”  An area that is believed to be capable of producing crude oil, NGLs, and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

Developed acreage.”  Acreage consisting of leased acres spaced or assignable to productive wells.  Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Development well.”  A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.

Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
i

Dry hole.”  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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

Field.”  An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation.”  A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or Gross wells.”  The total acres or wells, as the case may be, in which a working interest is owned.

Held by operations.”  A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.

Held by production.”  A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.

Hydraulic fracturing.”  The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Infill well.”  A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit.  Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Net acres.”  The percentage ownership of gross acres.  Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

Net well.”  A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

NYMEX.”  The New York Mercantile Exchange.

OPEC.”  The Organization of Petroleum Exporting Countries.

Productive well.”  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Recompletion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Reservoir.”  A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Spacing.”  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

ii

Unconventional play.”  An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability.  These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.

Undeveloped acreage.”  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves.  Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.

Unit.”  The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.  Also, the area covered by a unitization agreement.

Wellbore.”  The hole drilled by the bit that is equipped for natural gas production on a completed well.  Also called well or borehole.

West Texas Intermediate or WTI.”  A light, sweet blend of oil produced from the fields in West Texas.

Working interest.”  The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

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

Possible reserves.”  The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

Pre-tax PV-10% or PV-10.”  The 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 in accordance with guidelines promulgated by the SEC.

Probable reserves.”  The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.

Proved developed producing reserves (PDPs).”  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed non-producing reserves (PDNPs). Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in 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 reserves.”  The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

Proved undeveloped drilling location.”  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

iii

Proved undeveloped reserves” or PUDs.”  Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.  Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir or an analogous reservoir.

(i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

Standardized measure.”  Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

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NORTHERN OIL AND GAS, INC.
FORM 10-Q

March 31, 2020

C O N T E N T S

  Page
PART I – FINANCIAL INFORMATION  
   
Item 1. Condensed Financial Statements (unaudited)
2
Condensed Balance Sheets
2
Condensed Statements of Operations
4
Condensed Statements of Cash Flows
5
Condensed Statements of Stockholders’ Equity
6
Notes to Condensed Financial Statements
7
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Item 3. Quantitative and Qualitative Disclosures about Market Risk
 
Item 4. Controls and Procedures
 
PART II – OTHER INFORMATION
 
Item 1. Legal Proceedings
 
Item 1A. Risk Factors
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 6. Exhibits
 
Signatures

1

PART I - FINANCIAL INFORMATION
Item 1. Condensed Financial Statements.
NORTHERN OIL AND GAS, INC.
CONDENSED BALANCE SHEETS

(In thousands, except par value and share data) March 31, 2020 December 31, 2019
ASSETS (Unaudited)
Current Assets:    
Cash and Cash Equivalents $ 8,512    $ 16,068   
Accounts Receivable, Net 97,580    108,274   
Advances to Operators 567    893   
Prepaid Expenses and Other 2,216    1,964   
Derivative Instruments 245,552    5,628   
Income Tax Receivable 420    210   
Total Current Assets 354,847    133,037   
Property and Equipment:    
Oil and Natural Gas Properties, Full Cost Method of Accounting    
Proved 4,265,534    4,178,605   
Unproved 10,846    11,047   
Other Property and Equipment 2,156    2,157   
Total Property and Equipment 4,278,536    4,191,809   
Less – Accumulated Depreciation, Depletion and Impairment (2,504,735)   (2,443,216)  
Total Property and Equipment, Net 1,773,801    1,748,593   
Derivative Instruments 94,329    8,554   
Deferred Income Taxes —    210   
Other Noncurrent Assets, Net 14,409    15,071   
Total Assets $ 2,237,386    $ 1,905,465   
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:    
Accounts Payable $ 58,447    $ 69,395   
Accrued Liabilities 101,302    110,374   
Accrued Interest 9,308    11,615   
Derivative Instruments 130    11,298   
Current Portion of Long-term Debt 65,000    —   
Other Current Liabilities 891    795   
Total Current Liabilities 235,078    203,477   
Long-term Debt 975,282    1,118,161   
Derivative Instruments 547    8,079   
Asset Retirement Obligations 17,198    16,759   
Other Noncurrent Liabilities 273    345   
TOTAL LIABILITIES $ 1,228,379    $ 1,346,822   
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS’ EQUITY    
2

Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized;
2,294,702 Series A Shares Outstanding at 3/31/2020
1,500,000 Series A Shares Outstanding at 12/31/2019
   
Common Stock, Par Value $.001; 675,000,000 Shares Authorized;
 405,803,181 Shares Outstanding at 3/31/2020
 406,085,183 Shares Outstanding at 12/31/2019
406    406   
Additional Paid-In Capital 1,513,516    1,431,438   
Retained Deficit (504,917)   (873,203)  
Total Stockholders’ Equity 1,009,007    558,643   
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 2,237,386    $ 1,905,465   

The accompanying notes are an integral part of these condensed financial statements.
3

NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended
March 31,
(In thousands, except share and per share data) 2020 2019
REVENUES    
Oil and Gas Sales $ 130,196    $ 132,684   
Gain (Loss) on Commodity Derivatives, Net 376,581    (139,623)  
Other Revenue    
Total Revenues 506,785    (6,934)  
OPERATING EXPENSES    
Production Expenses 37,335    24,666   
Production Taxes 11,896    12,520   
General and Administrative Expense 4,871    6,051   
Depletion, Depreciation, Amortization and Accretion 61,809    45,134   
Total Operating Expenses 115,911    88,371   
INCOME (LOSS) FROM OPERATIONS 390,875    (95,305)  
OTHER INCOME (EXPENSE)    
Interest Expense, Net of Capitalization (16,551)   (19,548)  
Gain (Loss) on Unsettled Interest Rate Derivatives, Net (677)   —   
Loss on Extinguishment of Debt (5,527)   —   
Debt Exchange Derivative Gain —    6,287   
Contingent Consideration Gain —    1,392   
Other Income —    12   
Total Other Income (Expense) (22,755)   (11,857)  
INCOME (LOSS) BEFORE INCOME TAXES 368,120    (107,162)  
INCOME TAX PROVISION (BENEFIT) (166)   —   
NET INCOME (LOSS) $ 368,286    $ (107,162)  
Net Income (Loss) Per Common Share – Basic $ 0.90    $ (0.29)  
Net Income (Loss) Per Common Share – Diluted $ 0.74    $ (0.29)  
Weighted Average Shares Outstanding – Basic 403,662,541    371,448,566   
Weighted Average Shares Outstanding – Diluted 497,265,647    371,448,566   
The accompanying notes are an integral part of these condensed financial statements.
4

NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended
March 31,
(In thousands) 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES    
Net Income (Loss) $ 368,286    $ (107,162)  
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:    
Depletion, Depreciation, Amortization and Accretion 61,809    45,134   
Amortization of Debt Issuance Costs 1,461    1,301   
Loss on Extinguishment of Debt 5,527    —   
Amortization of Bond Premium on Long-term Debt (321)   (746)  
Deferred Income Taxes 210    —   
(Gain) Loss of Derivative Instruments (344,398)   152,169   
Gain on Debt Exchange Derivative —    (6,287)  
Loss on Contingent Consideration —    (1,392)  
PIK Interest on Second Lien Notes —    1,742   
Stock-Based Compensation Expense 1,079    2,751   
Other (57)   (21)  
Changes in Working Capital and Other Items:    
Accounts Receivable, Net 10,789    5,939   
Prepaid and Other Expenses (251)   178   
Accounts Payable (1,514)   5,783   
Accrued Interest (2,290)   426   
Accrued Liabilities 327    (907)  
Net Cash Provided by Operating Activities 100,654    98,908   
CASH FLOWS FROM INVESTING ACTIVITIES    
Drilling and Development Capital Expenditures (78,962)   (69,786)  
Acquisition of Oil and Natural Gas Properties (25,537)   (8,122)  
Purchases of Other Property and Equipment —    (5)  
Net Cash Used for Investing Activities (104,500)   (77,913)  
CASH FLOWS FROM FINANCING ACTIVITIES    
Advances on Revolving Credit Facility 25,000    53,000   
Repayments on Revolving Credit Facility (15,000)   (46,000)  
Repurchases of Second Lien Notes (13,277)   —   
Debt Issuance Costs Paid (37)   (70)  
Debt Exchange Derivative Settlements —    (894)  
Contingent Consideration Settlements —    (9,778)  
Repurchases of Common Stock —    (15,108)  
Restricted Stock Surrenders - Tax Obligations (396)   (558)  
Net Cash Used for Financing Activities (3,710)   (19,409)  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (7,555)   1,586   
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD 16,068    2,358   
CASH AND CASH EQUIVALENTS – END OF PERIOD 8,512    3,944   
The accompanying notes are an integral part of these condensed financial statements.
5

NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)


(In thousands, except share data) Common Stock Preferred Stock Additional Paid-In Retained
Earnings
Total Stockholders’
Equity
  Shares Amount Shares Amount Capital (Deficit) (Deficit)
December 31, 2019 406,085,183    $ 406    1,500,000    $   $ 1,431,438    $ (873,203)   $ 558,643   
Issuance of Common Stock 50,000    —    —    —    —    —    —   
Share Based Compensation —    —    —    —    1,263    —    1,263   
Restricted Stock Surrenders - Tax Obligations (332,002)   —    —    —    (396)   —    (396)  
Issuance of Preferred Stock, Net of Issuance Costs —    —    794,702      81,211    —    81,212   
Net Income —    —    —    —    —    368,286    368,286   
March 31, 2020 405,803,181    $ 406    2,294,702    $   $ 1,513,516    $ (504,917)   $ 1,009,007   


  Common Stock Preferred Stock Additional Paid-In Retained
Earnings
Total Stockholders’
Equity
(In thousands, except share data) Shares Amount Shares Amount Capital (Deficit) (Deficit)
December 31, 2018 378,333,070    $ 378    —    $ —    $ 1,226,371    $ (796,884)   $ 429,865   
Issuance of Common Stock 3,160,200      —    —    —    —     
Restricted Stock Forfeitures (4,802)   —    —    —    —    —    —   
Stock-Based Compensation —    —    —    —    2,832    —    2,832   
Restricted Stock Surrenders - Tax Obligations (220,531)   —    —    —    (558)   —    (558)  
Repurchases of Common Stock (5,635,003)   (6)   —    —    (15,102)   —    (15,108)  
Contingent Consideration Settlements 1,167,544      —    —    2,886    —    2,887   
Net Loss —    —    —    —    —    (107,162)   (107,162)  
March 31, 2019 376,800,478    $ 377    —    $ —    $ 1,216,429    $ (904,046)   $ 312,760   


The accompanying notes are an integral part of these condensed financial statements.
6

NOTES TO CONDENSED FINANCIAL STATEMENTS
MARCH 31, 2020
(UNAUDITED)

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Delaware corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties. The Company’s common stock trades on the NYSE American market under the symbol “NOG”.

Northern’s principal business is crude oil and natural gas exploration, development, and production with operations that primarily target the Bakken and Three Forks formations in the Williston Basin of the United States. The Company acquires leasehold interests that comprise of non-operated working interests in wells and in drilling projects within its area of operations.

For the three months ended March 31, 2020, crude oil accounted for 79% of the Company’s total production and 89% of its oil and gas sales.


NOTE 2     BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial information included herein is unaudited. The balance sheet as of December 31, 2019 has been derived from the Company’s audited financial statements for the year ended December 31, 2019. However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2019, which were included in the Company’s 2019 Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Revenues, expenses, cash flows, assets and liabilities can and do vary during each quarter of the year. Additionally, in March 2020, the World Health Organization declared novel coronavirus 2019 (“COVID-19”) a pandemic. The broader implication of COVID-19 on our results of operations and overall financial performance remains uncertain. We may experience various effects that could materially adversely impact our business, financial condition, results of operations and overall financial performance in future periods.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  

The most significant estimates relate to proved crude oil and natural gas reserves, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of oil and natural gas properties, asset retirement obligations and deferred income taxes.  Actual results may differ from those estimates.

Adopted and Recently Issued Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses (Topic 326) - Measurement of credit losses on financial instruments, which requires a company immediately recognize management’s current estimated credit losses (“CECL”) for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be
7

recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the condensed financial statements or notes accompanying the condensed financial statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair value measurement (Topic 820) - Disclosure framework - Changes to the disclosure requirements for fair value measurement, which modifies the disclosure requirements on fair value measurements in Topic 820. The Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the condensed financial statements or notes accompanying the condensed financial statements.

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes, which simplifies the accounting for income taxes by removing certain exceptions to the general principles and also simplification of areas such as separate entity financial statements and interim recognition of enactment of tax laws or rate changes. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim reporting periods within those years. The Company is currently evaluating the effect of ASU 2019-12, but does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or result of operations.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (LIBOR). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging
relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company’s condensed financial statements.

Revenue Recognition

The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable.

A wellhead imbalance liability equal to the Company’s share is recorded to the extent that the Company’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, for the three months ended March 31, 2020 and 2019, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.

The Company’s disaggregated revenue has two revenue sources, which are oil sales and natural gas and NGL sales, and the Company only operates in one geographic area, the Williston Basin in the United States, primarily in North Dakota and Montana. Oil sales for the three months ended March 31, 2020 and 2019 were $116.3 million and $123.6 million, respectively. Natural gas and NGL sales for the three months ended March 31, 2020 and 2019 were $13.9 million and $9.1 million, respectively.

Concentrations of Market, Credit and Other Risks

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas.  The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, economic disruptions resulting from the COVID-19 pandemic, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the crude oil and natural gas industry.  The Company’s receivables include amounts due, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production.  While certain of these customers, as well as third-party operators of the wells, are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial.

As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the development, exploitation, production and exploration activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the
8

Company’s financial condition and results of operation could be adversely affected. These risks are heightened in the current low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the three months ended March 31, 2020, the Company’s top four operators made up 53% of total oil and gas sales, compared to 59% for the three months ended March 31, 2019.

The Company faces concentration risk due to the fact that all of its oil and natural gas properties are located in the Williston Basin, primarily in North Dakota and Montana. As a result, the Company is disproportionately exposed to risks affecting its single geographic area of operations.

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.

Net Income (Loss) Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (loss) available to common stockholders (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares issuable upon exercise of stock options and vesting of restricted stock awards, and shares issuable upon conversion of the Series A Preferred Stock (see Note 5). The number of potential common shares outstanding are calculated using treasury stock or if-converted method.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2020 and 2019 are as follows:

  Three Months Ended
March 31,
(In thousands, except share and per share data) 2020 2019
Net Income (Loss) $ 368,286    $ (107,162)  
Less: Cumulative Dividends on Preferred Stock (3,729)   —   
Net Income (Loss) Attributable to Common Stock $ 364,557    $ (107,162)  
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic 403,662,541    371,448,566   
Plus: Dilutive Effect of Restricted Stock 354,658    —   
Plus: Dilutive Effect of Preferred Shares 93,248,448    —   
Weighted Average Common Shares Outstanding – Diluted 497,265,647    371,448,566   
Net Income (Loss) per Common Share:
Basic $ 0.90    $ (0.29)  
Diluted $ 0.74    $ (0.29)  
Shares underlying Restricted Stock Awards Excluded from EPS Due to Anti-Dilutive Effect 143,818 1,278,489   


9

Supplemental Cash Flow Information

The following reflects the Company’s supplemental cash flow information:

Three Months Ended March 31,
(In thousands) 2020 2019
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized $ 15,990    $ 16,929   
Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities 143,220    133,872   
Capitalized Asset Retirement Obligations 259    226   
Compensation Capitalized on Oil and Gas Properties 184    84   
Non-cash Financing Activities:
Issuance of 8.50% Second Lien Notes due 2023 - PIK Interest
—    1,738   
Issuance of Preferred Stock for 2L Notes Repurchase 81,212    —   
Contingent Consideration Settlements —    2,887   


NOTE 3     CRUDE OIL AND NATURAL GAS PROPERTIES

The Company follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”).  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.  Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.  Costs associated with production and general corporate activities are expensed in the period incurred.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.  The test determines a limit, or ceiling, on the book value of the proved oil and gas properties.  Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The Company did not have any ceiling test impairment for the three months ended March 31, 2020 and 2019, respectively.

At March 31, 2020, the Company’s impairment review used prices that reflect an average of the trailing 12-month prices as prescribed pursuant to the SEC’s guidelines. The average prices used in the March 31, 2020 impairment review are significantly higher than the actual and currently forecasted prices for 2020. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation for future fiscal quarters, the present value of the Company’s future net revenues is expected to decline and a material impairment is expected to be recognized. Given the current oil and natural gas pricing environment, the Company expects it will have noncash ceiling test write-downs of its oil and natural gas properties in 2020.

The book value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs.  Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying condensed statements of operations from the closing date of the acquisition.  Acquired assets and liabilities assumed are recorded based on their estimated fair value at the time of the acquisition.  Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.


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2020 Acquisitions

The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $25.5 million during the three months ended March 31, 2020. These amounts include $18.4 million, of development costs that occurred prior to the closings of the acquisitions.

2019 Acquisitions

The Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $8.4 million during the three months ended March 31, 2019.

VEN Bakken Acquisition

On July 1, 2019, the Company completed its acquisition (the “VEN Bakken Acquisition”) of certain oil and gas properties and interests from VEN Bakken, LLC (“VEN Bakken”), effective as of July 1, 2019. VEN Bakken is a wholly-owned subsidiary of Flywheel Bakken, LLC. At closing the acquired assets consisted of approximately 90.1 net producing wells and 3.3 net wells in process, as well as approximately 18,000 net acres substantially all in North Dakota. The Company also assumed certain crude oil derivative contracts from VEN Bakken as part of the acquisition. The VEN Bakken Acquisition was completed pursuant to the purchase and sale agreement between the Company and VEN Bakken, dated as of April 18, 2019.

The total estimated consideration paid by the Company was $315.3 million, consisting of (i) $174.9 million in cash, (ii) 5,602,147 shares of Company common stock valued at $11.7 million, based on the $2.09 per share closing price of Company common stock on the closing date of the acquisition and (iii) $128.7 million of value attributable to a 6.0% unsecured promissory note due July 1, 2022 issued by the Company to VEN Bakken in the aggregate principal amount of $130.0 million (the “Unsecured VEN Bakken Note”). The Company incurred $1.8 million of transactions costs in connection with the acquisition, which are included in general and administrative expense in the condensed statement of operations. The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:

(In thousands)
Fair value of net assets:
  Proved oil and natural gas properties $ 324,974   
  Asset retirement cost 2,680   
Total assets acquired 327,654   
  Asset retirement obligations (2,680)  
  Derivative instruments (9,694)  
Net assets acquired $ 315,280   
Fair value of consideration paid for net assets:
  Cash consideration $ 174,912   
  Issuance of common stock (5.6 million shares at $2.09 per share)
11,708   
  Unsecured VEN Bakken Note 128,660   
Total fair value of consideration transferred $ 315,280   

Pro Forma Information

The following summarized unaudited pro forma condensed statement of operations information for the three months ended March 31, 2019, assumes that the VEN Bakken Acquisition occurred as of January 1, 2019. There is no pro forma information included for the three months ended March 31, 2020, because the Company’s actual financial results for such period fully reflect this acquisition. The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed the acquisition as of January 1, 2019, or that would be attained in the future.
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Three Months Ended
(In thousands) March 31, 2019
Revenues $ (13,515)  
Net Loss (139,749)  

Unproved Properties

All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.

The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators.  The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.

The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur.  The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.

Capitalized costs associated with impaired unproved properties, which includes leases that have expired or have been deemed uneconomic, and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the three months ended March 31, 2020 and 2019, unproved properties of $1.7 million and $0.7 million, respectively, were impaired.


NOTE 4     LONG-TERM DEBT

The Company’s long-term debt consists of the following:

(in thousands) March 31, 2020 December 31, 2019
Revolving Credit Facility $ 590,000    $ 580,000   
Second Lien Notes due 2023 327,489    417,733   
Unsecured VEN Bakken Note 130,000    130,000   
Total principal 1,047,489    1,127,733   
Unamoritzed debt discounts and premiums 3,244    4,860   
Unamortized debt issuance costs (1) (10,450)   (14,432)  
Total debt 1,040,282    1,118,161   
Less current portion of long-term debt (65,000)   —   
Total long-term debt $ 975,282    $ 1,118,161   
________________
(1)Debt issuance costs related to the Company’s revolving credit facility of $9.3 million and $9.8 million as of March 31, 2020 and December 31, 2019, respectively, are recorded in “Other Noncurrent Assets, Net” on the balance sheets.

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Revolving Credit Facility

On November 22, 2019, the Company entered into a Second Amended and Restated Credit Agreement (the “Revolving Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto, which amended and restated the Company’s prior revolving credit facility that was entered into on October 5, 2018. The Revolving Credit Facility is scheduled to mature on November 22, 2024, provided that the maturity date shall be 91 days prior to the scheduled maturity date of the earlier of (i) the Second Lien Notes (defined below) if any Second Lien Notes remain outstanding on such date or (ii) the Unsecured VEN Bakken Note if any principal amount of the Unsecured VEN Bakken Note remains outstanding on such date.

The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to the Company and its subsidiaries’ (if any) oil and gas properties. The borrowing base as of March 31, 2020 was $800.0 million. The borrowing base will be redetermined semiannually on or around April 1st and October 1st, with one interim “wildcard” redetermination available between scheduled redeterminations. The April 1st scheduled redetermination shall be based on a January 1st engineering report audited by a third party (reasonably acceptable by the Agent). The Company’s April 1st, 2020 redetermination is still in process.

At the Company’s option, borrowings under the Revolving Credit Facility shall bear interest at the base rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans ranges from 200 to 300 basis points, in each case depending on the percentage of the borrowing base utilized.

The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, or make certain types of investments. In addition, the Revolving Credit Facility requires that the Company comply with the following financial covenants: (i) as of the date of determination, the ratio of total net debt to EBITDAX (as defined in the Revolving Credit Facility) shall be no more than 3.50 to 1.00, measured on a pro forma rolling four quarter basis, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under FASB ASC 815, divided by consolidated current liabilities excluding current non-cash obligations under FASB ASC 815 and current maturities under the Revolving Credit Facility, the Second Lien Notes and the Unsecured VEN Bakken Note) shall not be less than 1.00 to 1.00. The Company is in compliance with these financial covenants as of March 31, 2020.

The Company’s obligations under the Revolving Credit Facility may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the Revolving Credit Facility). Such Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of us or the Company’s subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the Revolving Credit Facility).

The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 85% of the value of proven reserves associated with the oil and gas properties included in the determination of the borrowing base. Additionally, the Company entered into a Guaranty and Collateral Agreement in favor of the Agent for the secured parties, pursuant to which the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in substantially all of the Company’s assets.

Second Lien Notes due 2023

On May 15, 2018, the Company issued 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) with an aggregate principal amount of $344.3 million (the “Original 2L Notes”) in exchange for certain previously outstanding 8.000% senior unsecured notes due June 1, 2020 (the “Unsecured Notes”). In October 2018, the Company issued an additional $350.0 million aggregate principal amount of Second Lien Notes (the “Additional 2L Notes”), the proceeds of which were used in connection with the retirement of the Company’s prior term loan credit agreement. In addition, as of and through March 31, 2020, the Company had issued another $4.3 million of additional aggregate principal amount of Second Lien Notes pursuant to the interest payment-in-kind provisions thereof.


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During 2019, the Company repurchased and retired $10.1 million in aggregate principal amount of Second Lien Notes in open market transactions. In November 2019, the Company completed a cash tender offer to redeem and repay $200.0 million principal amount of Second Lien Notes. Also in November 2019, the Company redeemed and repaid $70.8 million principal amount of Second Lien Notes in exchange for Series A Preferred Stock. In January 2020, the Company completed four independent, separately negotiated purchase agreements to repurchase and retire $76.7 million aggregate principal amount of Second Lien Notes in exchange for Series A Preferred Stock and cash. During the three months ended March 31, 2020, the Company repurchased and retired $13.5 million aggregate principal amount of Second Lien Notes in open market transactions.

The terms of the Second Lien Notes include those stated in the Indenture entered into on May 15, 2018 by the Company and Wilmington Trust, National Association, as trustee (the “Original 2L Indenture”), as amended by the First Supplemental Indenture, dated September 18, 2018 (the “First Supplemental 2L Indenture”), the Second Supplemental Indenture, dated October 5, 2018 (the “Second Supplemental 2L Indenture”), and the Third Supplemental Indenture, dated November 22, 2019 (the “Third Supplemental 2L Indenture” and, together with the Original 2L Indenture, the First Supplemental 2L Indenture, and the Second Supplemental 2L Indenture, the “2L Indenture”).

The Second Lien Notes are the senior secured obligations of the Company and rank equal in right of payment to all existing and future senior indebtedness of the Company and its subsidiaries. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company, subject to certain exceptions. The Second Lien Notes will be guaranteed by all of the Company’s direct and indirect subsidiaries that guarantee indebtedness under any other indebtedness for borrowed money of the Company or any of the Company’s subsidiary guarantors. As of March 31, 2020, the Company did not have any subsidiaries. The Second Lien Notes will mature on May 15, 2023.

Interest on the Second Lien Notes accrues at a rate of 8.500% per annum payable in cash quarterly in arrears on the first day of each calendar quarter. Additional interest may accrue depending on the Company’s total debt to EBITDAX ratio as of each December 31st and June 30th, provided that any such additional interest would be payable in kind (the “PIK Interest”). No PIK Interest will accrue so long as the Company’s total debt to EBITDAX ratio remains below 2.50 to 1.00 as of each applicable measurement date. PIK Interest of 1.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is less than 2.75 to 1.00 but equal to or greater than 2.50 to 1.00. PIK Interest of 2.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is less than 3.00 to 1.00 but equal to or greater than 2.75 to 1.00. PIK Interest of 3.00% per annum will accrue if the Company’s total debt to EBITDAX ratio is greater than or equal to 3.00 to 1.00. No PIK Interest has accrued since March 31, 2019. Default interest will be payable in cash on demand at the then applicable interest rate plus 3.00% per annum.

The Company may redeem all or a portion of any of the Second Lien Notes at the following redemption prices during the following time periods (plus accrued and unpaid interest on the Second Lien Notes redeemed): (i) from and after May 15, 2018 until May 15, 2021, 104%, (ii) on and after May 15, 2021 until May 15, 2022, 102%, and (iii) on and after May 15, 2022, 100%; provided that any redemption of Second Lien Notes (or the acceleration of Second Lien Notes) prior to May 15, 2020 shall also be accompanied by a make whole premium. Subject to the terms of an intercreditor agreement, the Company is also required to offer to prepay the Second Lien Notes with 100% of the net cash proceeds of asset sales, casualty events and condemnations in excess of $20.0 million not required to be used to pay down the loans under the Revolving Credit Facility, subject to customary exclusions and reinvestment provisions. Mandatory prepayment offers will be subject to payment of the make whole premium and redemption price set forth above, as applicable.

If a change of control occurs, the Company will be required to offer to repurchase the Second Lien Notes at the repurchase price of 101% of the principal amount of repurchased Second Lien Notes (subject to the prepayment provisions of the Revolving Credit Facility). The Second Lien Notes contain negative covenants that limit the Company’s ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, make certain types of investments, amend other debt documents, and incur any additional debt on a subordinated or junior basis to the Revolving Credit Facility and on a senior basis to the Second Lien Notes. The Second Lien Notes do not include any financial maintenance covenants.

The obligations of the Company under the Second Lien Notes may be accelerated upon the occurrence of an Event of Default (as such term is defined in the 2L Indenture). Events of Default include customary events for a capital markets debt financing of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the 2L Indenture).


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Unsecured VEN Bakken Note

On July 1, 2019, in connection with the completion of the VEN Bakken Acquisition, the Company issued the Unsecured VEN Bakken Note in the original principal amount of $130.0 million (see Note 3 above). Fifty percent (50%) of the original principal amount of the Unsecured VEN Bakken Note is required to be repaid by the Company on or before January 1, 2021, and the remaining unpaid principal amount is required to be repaid by the Company on or before July 1, 2022, in each case together with all accrued but unpaid interest thereon. Interest, at a rate of 6.0% per annum, is due quarterly in arrears on the first day of each calendar quarter, commencing on October 1, 2019. The Unsecured VEN Bakken Note does not include any financial maintenance covenants and is unsecured.

The obligations of the Company under the Unsecured VEN Bakken Note may be accelerated, subject to certain grace and cure periods, upon the occurrence of an event of default. Events of default include customary events, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of certain affirmative or negative covenants, defaults on other indebtedness of the Company, and bankruptcy or insolvency related defaults. The Unsecured VEN Bakken Note contains negative covenants that limit the Company’s ability, among other things, to pay dividends, repurchase equity, incur additional indebtedness, sell assets, terminate or unwind certain derivatives contracts, change the nature of its business or operations and merge or consolidate. In addition, the Unsecured VEN Bakken Note is subject to a mandatory prepayment offer in connection with a change of control.


NOTE 5    COMMON AND PREFERRED STOCK

Common Stock

The Company is authorized to issue up to 675,000,000 shares of common stock, par value $0.001 per share. As of March 31, 2020, the Company had 405,803,181 shares of common stock issued and outstanding.

Preferred Stock

The Company is authorized to issue up to 5,000,000 shares of preferred stock, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. As of March 31, 2020 the Company had 2,294,702 shares of preferred stock issued and outstanding, respectively, all of which were shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”).

The terms of the Series A Preferred Stock are set forth in the Certificate of Designations for the Series A Preferred Stock (the “Certificate of Designations”), as originally filed with the Delaware Secretary of State on November 22, 2019, and as amended thereafter. The Series A Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding-up. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the board of directors of the Company, cumulative dividends in cash, at a rate of 6.500% per annum on the sum of (i) the $100 liquidation preference per share of Series A Preferred Stock (the “Liquidation Preference”) and (ii) all accumulated and unpaid dividends (if any), payable semi-annually in arrears on May 15 and November 15 of each year, commencing on May 15, 2020. As of March 31, 2020, there were $5.3 million of accumulated dividends on the Series A Preferred Stock, which are not reflected in the condensed financial statements because they have not been declared.

The Series A Preferred Stock is convertible at the holders’ option (an “Optional Conversion”) into common stock at a conversion rate set forth in the Certificate of Designations, subject to customary adjustments as provided for therein. As of March 31, 2020, the conversion rate was 43.63 shares of common stock for each share of Series A Preferred Stock (which is equivalent to a conversion price of approximately $2.292 per share of Common Stock). Holders may be entitled to additional shares of common stock or cash in connection with a conversion that occurs in connection with a Fundamental Change (as defined in the Certificate of Designations). The Series A Preferred Stock is convertible at the Company’s option (a “Mandatory Conversion”) if the closing sale price of the Company’s common stock equals or exceeds 145% of the conversion price for at least 20 trading days (whether or not consecutive) in a period of 30 consecutive trading days. A Mandatory Conversion would also entitle the holder to a cash payment equal to eight semi-annual dividend payments, less an amount equal to all cash dividend payments made in respect of such holder’s shares of Series A Preferred Stock prior to such Mandatory Conversion. The occurrence of any Optional Conversion or Mandatory Conversion is subject to various terms and limitations set forth in the Certificate of Designations.

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The Certificate of Designations also sets forth additional information relating to the payment of dividends, voting, conversion rights, consent rights, liquidation rights, the ranking of the Series A Preferred Stock in comparison with the Company’s other securities, and other matters.

2020 Activity

Common Stock

During the three months ended March 31, 2020, 0.3 million shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards.  The total value of these shares was approximately $0.4 million, which is based on the market prices on the dates the shares were surrendered.

Preferred Stock

During the three months ended March 31, 2020, the Company issued 794,702 shares of Series A Preferred Stock as part of separate transactions pursuant to which the Company retired $76.7 million in aggregate principal amount of Second Lien Notes (see Note 4).

Stock Repurchase Program

In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock.  The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.

During the three months ended March 31, 2020, the Company did not repurchase shares of its common stock under the stock repurchase program. During the three months ended March 31, 2019, the Company repurchased 5.6 million shares of its common stock under the stock repurchase program at a total cost of $16.3 million, of which $1.2 million was recorded as a settlement of contingent consideration liabilities. The Company’s accounting policy upon the repurchase of shares is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. All repurchased shares are now included in the Company’s pool of authorized but unissued shares.


NOTE 6     STOCK-BASED COMPENSATION

The Company’s 2018 Equity Incentive Plan (the “2018 Plan”), which replaced the Company’s prior 2013 Incentive Plan (the “2013 Plan”), authorized 15,000,000 shares for grant under the 2018 Plan, plus the 769,775 shares remaining available for future grants under the 2013 Plan on the date the stockholders approved the 2018 Plan. No future awards will be made under the 2013 Plan. The 2013 Plan continues to govern awards that were made thereunder, which remain in effect pursuant to their terms. As of March 31, 2020, there were 12,563,710 shares available for future awards under the 2018 Plan.

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company’s stock-based compensation awards are accounted for as equity instruments and are included in the “General and administrative” line item in the unaudited statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the “Oil and natural gas properties” line item on the unaudited balance sheets.

The 2018 Plan and 2013 Plan award types are summarized as follows:

Restricted Stock Awards

The Company issues restricted stock awards (“RSAs”) subject to various vesting conditions as compensation to executive officers, employees and directors of the Company. RSAs issued to employees and executive officers generally vest over three years, provided that any performance and/or market conditions are also met. RSAs issued to directors generally vest over one year, provided that any performance and/or market conditions are also met. For RSAs subject to service and/or performance vesting conditions, the grant-date fair value is established based on the closing price of the Company’s common stock on such date. Stock-based compensation expense for awards subject to only service conditions is recognized on a straight-line basis over the service period. Stock-based compensation expense for awards with both service and performance conditions is recognized
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on a graded basis only if it is probable that the performance condition will be achieved. The Company accounts for forfeitures of awards granted under these plans as they occur in determining stock-based compensation expense.

For awards subject to a market condition, the grant-date fair value is estimated using a Monte Carlo valuation model. The Company recognizes stock-based compensation expense for awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and stock-based compensation expense for any such awards is not reversed if vesting does not actually occur. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of the Company’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.

The following table reflects the outstanding RSAs and activity related thereto for the three months ended March 31, 2020:

Service-based Awards Service and Performance-based Awards Service and Market-based Awards Service, Performance, and Market-based Awards
Number of Shares Weighted-average Grant Date Fair Value Number of Shares Weighted-average Grant Date Fair Value Number of Shares Weighted-average Grant Date Fair Value Number of Shares Weighted-average Grant Date Fair Value
Outstanding at December 31, 2019 414,004    $ 2.41    375,000    $ 2.70    1,189,661    $ 1.80    708,000    $ 0.98   
Shares granted 50,000    2.23    —    —    —    —    —    —   
Shares forfeited —    —    —    —    —    —    —    —   
Shares vested (241,795)   2.58    (212,500)   2.70    (69,168)   1.67    (316,000)   0.98   
Outstanding at March 31, 2020 222,209    $ 2.19    162,500    $ 2.70    1,120,493    $ 1.81    392,000    $ 0.98   

At March 31, 2020, there was $2.3 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 0.7 years. For the three months ended March 31, 2020 and 2019, the total fair value of the Company’s restricted stock awards vested was $1.2 million and $2.0 million, respectively.


NOTE 7     RELATED PARTY TRANSACTIONS

On October 21, 2019, the Company announced the commencement of (i) a cash tender offer (the “Tender Offer”) to purchase up to $200.0 million in aggregate principal amount of the Company’s Second Lien Notes; (ii) an exchange offer (the “Exchange Offer”) to eligible holders of Second Lien Notes to exchange up to $70.8 million in aggregate principal amount of Second Lien Notes for shares of the Company’s newly issued Series A Preferred Stock; (iii) a related solicitation of consents (the “Consent Solicitation”) to adopt certain proposed amendments to the indenture for the Second Lien Notes; and (iv) an offer to eligible holders of Second Lien Notes to subscribe to purchase for up to $75.0 million in cash additional shares of Series A Preferred Stock (the “Subscription Offer”). Parties affiliated with TRT Holdings, Inc. (collectively, the “TRT Parties”) held Second Lien Notes and thus had the right to participate in the Tender Offer, Exchange Offer, Consent Solicitation and Subscription Offer on terms identical to the terms generally offered to all holders of Second Lien Notes. These transactions closed on November 22, 2019, with the TRT Parties (i) exchanging $1.0 million aggregate principal amount of Second Lien Notes for 10,947 shares of Series A Preferred Stock pursuant to the Exchange Offer and (ii) acquiring 10,947 additional shares of Series A Preferred Stock for a purchase price of $1.1 million pursuant to the Subscription Offer. On February 20, 2020, the Company entered into an exchange agreement (the “Exchange Agreement”) with the TRT Parties related to the Series A Preferred Stock, as follows. The certificate of designations of the Series A Preferred Stock, as amended (the “Certificate of Designations”), contains limitations on the ability of the company or holders of Series A Preferred Stock to effect conversions of shares of Series A Preferred Stock for shares of the Company’s common stock if after a conversion a holder would beneficially own shares of common stock in excess of 9.99% of the aggregate number of shares of the Company’s common stock outstanding immediately after giving pro forma effect to the issuance of shares upon such conversion (the “Conversion Cap”). As of the date of the Exchange Agreement, the TRT Parties collectively beneficially owned a number of shares of the Company’s common stock in excess of the Conversion Cap. The Exchange Agreement provides, notwithstanding anything to the contrary in the Certificate of Designations, including the Conversion Cap, for the TRT Parties to be able to exchange shares of Series A Preferred Stock for shares of the Company’s common stock in the manner otherwise contemplated by the Certificate of Designations. As of the date hereof, the TRT Parties have not exchanged or converted any shares of Series A Preferred Stock into Common Stock. Two of our directors, Mr. Frantz and Mr. Popejoy, are employed by the TRT Parties and the TRT Parties beneficially owned in excess of 10% of the Company’s outstanding common stock at the time of the transactions described in this paragraph.

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In January 2019, the Company repurchased 3.7 million shares of Company common stock from W Energy Partners LLC (“W Energy”) for cash consideration of $11.1 million. The repurchased shares were originally issued by the Company as partial consideration for an acquisition of oil and gas properties from W Energy during 2018. W Energy beneficially owned in excess of 10% of the Company’s outstanding common stock at the time of the repurchase transactions.

The Company’s Audit Committee is responsible for approving all transactions involving related parties, including each of the transactions identified above.


NOTE 8     COMMITMENTS & CONTINGENCIES

Litigation

The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention.  Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows.  Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.

The Company’s interests in certain crude oil and natural gas leases from the State of North Dakota are subject to an ongoing dispute over the ownership of minerals underlying the bed of the Missouri River within the boundaries of the Fort Berthold Reservation.  The ongoing dispute is between the State of North Dakota and three affiliated tribes, both of whom have purported to lease mineral rights in tracts of riverbed within the reservation boundaries. In the event the ongoing dispute results in a final judgment that is adverse to the Company’s interests, the Company would be required to reverse approximately $4.6 million in revenue (net of accrued taxes) that has been accrued since the first quarter of 2013 based on the Company’s purported interest in the crude oil and natural gas leases at issue. Due to the long-term nature of this title dispute, the $4.6 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the condensed balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases.


NOTE 9     INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three months ended March 31, 2020 and 2019 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income due to the recognition of a full valuation allowance during both the three months ended March 31, 2020 and 2019, respectively.

In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the projected future income and results of operations, and (iv) its ability to use tax planning strategies. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. At December 31, 2019, the Company had a valuation allowance totaling $144.2 million on its net DTAs, and as of March 31, 2020, the Company maintains a full valuation allowance on its net DTAs.

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (CARES) Act was signed into law making several changes to the Internal Revenue Code. The changes include, but are not limited to: increasing the limitation on the amount of deductible interest expense, allowing companies to carryback certain net operating losses, and increasing the amount of net operating loss carryforwards that corporations can use to offset taxable income. The tax law changes in the Act did not have a material impact on the Company’s income tax provision.






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NOTE 10     FAIR VALUE

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.  The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:

Level 1 - Quoted prices in active markets for identical assets or liabilities.

Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Financial Assets and Liabilities

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2020 and December 31, 2019:

  Fair Value Measurements at March 31, 2020 Using
(In thousands) Quoted Prices In Active Markets for Identical Assets (Liabilities)
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Commodity Derivatives – Current Asset (crude oil price swaps) $ —    $ 245,552    $ —   
Commodity Derivatives – Noncurrent Asset (crude oil price and crude oil price swaptions) —    94,329    —   
Interest Rate Derivatives – Current Liabilities —    (130)   —   
Interest Rate Derivatives – Noncurrent Liabilities —    (547)   —   
Total $ —    $ 339,204    $ —   

  Fair Value Measurements at December 31, 2019 Using
 (In thousands) Quoted Prices In Active Markets for Identical Assets (Liabilities)
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Commodity Derivatives – Current Asset (crude oil price swaps) $ —    $ 5,628    $ —   
Commodity Derivatives – Current Liabilities (crude oil price swaps) —    (11,298)   —   
Commodity Derivatives – Noncurrent Asset (crude oil price swaps and crude oil price swaptions) —    8,554    —   
Commodity Derivatives – Noncurrent Liabilities (crude oil price swaps and crude oil swaptions) —    (8,079)   —   
Total $ —    $ (5,195)   $ —   
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Commodity Derivatives. The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 11).  The fair value of the Company’s commodity derivative instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs.  The Company’s and the counterparties’ nonperformance risk is evaluated.  The fair value of commodity derivative contracts is reflected on the condensed balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.

Interest Rate Derivatives. The Level 2 instruments presented in the tables above consist of interest rate derivative instruments (see Note 11).  The fair value of the Company’s interest rate derivative instruments is determined based upon contracted notional amounts, active market-quoted LIBOR yield curves, and time to maturity, among other things. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs.  The Company’s and the counterparties’ nonperformance risk is evaluated.  The fair value of interest rate derivative contracts is reflected on the condensed balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.

Fair Value of Other Financial Instruments

The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.

Long-term debt is not presented at fair value on the balance sheets, as it is recorded at carrying value, net of unamortized debt issuance costs and unamortized premium or discount (see Note 4).  The fair value of the Company’s Second Lien Notes is $194.9 million and $434.4 million at March 31, 2020 and December 31, 2019, respectively. The fair value of the Company’s Second Lien Notes are based on active market quotes, which represent Level 1 inputs.

There is no active market for the Revolving Credit Facility or the Unsecured VEN Bakken Note. The recorded value of the Revolving Credit Facility approximates its fair value because of its floating rate structure based on the LIBOR spread, secured interest, and the Company’s borrowing base utilization. The recorded value of the VEN Bakken Note approximates its fair value. The fair value measurements for the Revolving Credit Facility and the Unsecured VEN Bakken Note represent Level 2 inputs.

Non-Financial Assets and Liabilities

The Company estimates asset retirement obligations pursuant to the provisions of ASC 410.  The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties.  Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs.  Asset retirement obligations incurred and acquired during the three months ended March 31, 2020 were approximately $0.3 million.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.  There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the three months ended March 31, 2020.


NOTE 11     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity price swaps, basis swaps, swaptions and collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. In addition, in the first quarter of 2020, the Company began to utilize interest rate swaps to mitigate exposure to changes in interest rates on the Company’s variable-rate indebtedness.

All derivative instruments are recorded on the Company’s balance sheet as either assets or liabilities measured at their fair value (see Note 10).  The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes.  If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the Company’s condensed statements of operations as a gain or loss on derivative instruments.  Mark-to-market gains and losses represent changes in fair values of derivatives that have not been
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settled.  The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty.  These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

The Company has master netting agreements on individual derivative instruments with certain counterparties and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet for contracts with these counterparties.

Commodity Derivative Instruments

The following table presents settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented which is recorded in the revenue section of our condensed financial statements:
  Three Months Ended
March 31,
(In thousands) 2020 2019
Gain (Loss) on Settled Commodity Derivatives $ 31,506    $ 12,546   
Gain (Loss) on Unsettled Commodity Derivatives 345,075    (152,169)  
Gain (Loss) on Commodity Derivatives, Net $ 376,581    $ (139,623)  

As of March 31, 2020, the Company had a total volume on open commodity price swaps of 15.1 million barrels at a weighted average price of approximately $56.45 per barrel. The following table reflects the weighted average price of open commodity price swap derivative contracts as of March 31, 2020, by year with associated volumes.

Year Volumes (Bbl) Weighted
Average Price ($)
2020 7,441,988    58.05   
2021(1)
6,333,674    55.41   
2022(2)
1,372,866    52.57   
______________
(1)The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 0.3 million barrels for 2021 are exercisable on or about December 31, 2020. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 0.3 million barrels at a weighted average price of $57.84 per barrel for 2021.
(2)The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 2.6 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 2.6 million barrels at a weighted average price of $54.20 per barrel for 2022. Additionally, counterparties have options covering a notional volume of 0.2 million barrels for 2023 at a weighted average price of $43.00 per barrel.

Interest Rate Derivative Instruments

The Company uses interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. As of March 31, 2020, the Company had interest rate swaps with a total notional amount of $200.0 million. The settlement of these derivative instruments is recognized as a component of interest expense in the condensed statements of operations. The mark-to-market component of these derivative instruments is recognized in gain (loss) on unsettled interest rate derivatives, net in the condensed statements of operations.


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Other Information Regarding Derivative Instruments

The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at March 31, 2020 and December 31, 2019, respectively.  Certain amounts may be presented on a net basis on the condensed financial statements when such amounts are with the same counterparty and subject to a master netting arrangement.
Type of Contract Balance Sheet Location March 31, 2020 Estimated Fair Value December 31, 2019 Estimated Fair Value
Derivative Assets:   (In thousands)
Commodity Price Swap Contracts Current Assets $ 245,552    $ 20,164   
Interest Rate Swap Contracts Current Assets 151    —   
Commodity Price Swap Contracts Noncurrent Assets 99,800    16,069   
Interest Rate Swap Contracts Noncurrent Assets   —   
Total Derivative Assets   $ 345,503    $ 36,233   
Derivative Liabilities:      
Commodity Price Swap Contracts Current Liabilities $ —    $ (25,834)  
Interest Rate Swap Contracts Current Liabilities (281)   —   
Commodity Price Swap Contracts Noncurrent Liabilities —    (5,273)  
Interest Rate Swap Contracts Noncurrent Liabilities (548)   —   
Commodity Price Swaptions Contracts Noncurrent Liabilities (5,471)   (10,321)  
Total Derivative Liabilities   $ (6,299)   $ (41,428)  

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions.  When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted on the balance sheet.  The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet.  The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates.

  Estimated Fair Value at March 31, 2020
(In thousands) Gross Amounts of
Recognized Assets (Liabilities)
Gross Amounts Offset
on the Balance Sheet
Net Amounts of Assets (Liabilities) Presented in the Balance Sheet
Offsetting of Derivative Assets:  
Current Assets $ 245,703    $ (151)   $ 245,552   
Noncurrent Assets 99,800    (5,471)   94,329   
Total Derivative Assets $ 345,503    $ (5,622)   $ 339,881   
Offsetting of Derivative Liabilities:  
Current Liabilities $ (281)   $ 151    $ (130)  
Noncurrent Liabilities (6,019)   5,471    (547)  
Total Derivative Liabilities $ (6,299)   $ 5,622    $ (677)  

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  Estimated Fair Value at December 31, 2019
 (In thousands) Gross Amounts of
Recognized Assets (Liabilities)
Gross Amounts Offset
on the Balance Sheet
Net Amounts of Assets (Liabilities) Presented in the Balance Sheet
Offsetting of Derivative Assets:  
Current Assets $ 20,164    $ (14,536)   $ 5,628   
Non-Current Assets 16,069    (7,515)   8,554   
Total Derivative Assets $ 36,233    $ (22,051)   $ 14,182   
Offsetting of Derivative Liabilities:  
Current Liabilities $ (25,834)   $ 14,536    $ (11,298)  
Non-Current Liabilities (15,594)   7,515    (8,079)  
Total Derivative Liabilities $ (41,428)   $ 22,051    $ (19,377)  

All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with parties that are also lenders under the Company’s Revolving Credit Facility.  The Company’s obligations under the derivative instruments are secured pursuant to the Revolving Credit Facility, and no additional collateral had been posted by the Company as of March 31, 2020.  The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately.  See Note 10 for the aggregate fair value of all derivative instruments that were in a net liability position at March 31, 2020 and December 31, 2019.


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

Cautionary Statement Concerning Forward-Looking Statements

This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding future events and our future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”).  All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our revolving credit facility, and impairment are forward-looking statements.  When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes.  Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:  the effects of the COVID-19 pandemic and related economic slowdown, changes in crude oil and natural gas prices, the pace of drilling and completions activity on our current properties, infrastructure constraints and related factors affecting our properties, our ability to acquire additional development opportunities, changes in our reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which we conduct business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, health-related epidemics, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products and prices.

We have based any forward-looking statements on our current expectations and assumptions about future events.  While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  Accordingly, results achieved may differ materially from expected results described in these statements. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Forward-looking statements speak only as of the date they are made. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

The following discussion should be read in conjunction with the unaudited Condensed Financial Statements and accompanying Notes to Condensed Financial Statements appearing elsewhere in this report.

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana.  Our primary focus is oil exploration and production through non-operated working interests in wells drilled and completed in spacing units that include our acreage.  Using this strategy, we had participated in 6,251 gross (464.8 net) producing wells as of March 31, 2020.

Our average daily production in the first quarter of 2020 was approximately 43,735 Boe per day, of which approximately 79% was oil. Our acquisition and development activities in 2019 resulted in production in the first quarter of 2020 increasing by approximately 28% over the same period last year. During the three months ended March 31, 2020, we added 108 gross (7.3 net) wells to production. As of March 31, 2020, we had leased approximately 183,245 net acres, of which approximately 89% were developed and substantially all were located in the Williston Basin in North Dakota and Montana.

Outlook Given COVID-19 Pandemic and Current Economic Environment

The novel coronavirus disease (COVID-19) and efforts to mitigate the spread of the disease have created unprecedented challenges for our industry. As a result of lower demand caused by the COVID-19 pandemic and the oversupply
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of crude oil, spot and future prices of crude oil are at or near historic lows. Operators in the Williston Basin are responding by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Operators’ decisions on these matters are evolving rapidly, and it remains extremely difficult to predict the effects on our company and its business. See “Market Conditions” below. See also “Risk Factors” in Part II, Item 1A below for additional information.

We expect that our developmental capital expenditures will be significantly lower than previously anticipated if the current environment persists. We have reduced our 2020 developmental capital spending forecast to a range of $175.0 – $200.0 million, a reduction of 53% – 59% compared to our actual developmental capital expenditures in 2019.

We also anticipate that our production will be significantly lower than prior expectations as many of our operating partners have begun to shut-in or curtail production and defer development plans until commodity prices recover to economic levels. However, due to our crude oil derivative positions and reduction in capital expenditures, we expect to generate significant cash flow in 2020, despite the current market conditions, which can be used to reduce our outstanding debt. For the last nine months of 2020, we currently have an average of approximately 27,000 barrels of oil per day hedged at a weighted average NYMEX WTI price of $58.05 per barrel. By way of comparison, in the first quarter of 2020 our production of crude oil averaged 34,488 barrels per day which was approximately 85% hedged at a weighted average price of $57.93 per barrel. We anticipate our oil production will be lower throughout the year if the current environment persists.

We expect a reduction in the borrowing base under our revolving credit facility if the current environment persists. However, we believe that cash flow from operations (including settlement on commodity derivative instruments) and borrowing availability under our revolving credit facility will allow us to meet our liquidity needs for at least the next twelve 12 months, including the $65.0 million principal payment on the Unsecured VEN Bakken Note that is due January 1, 2021.

At March 31, 2020, we performed an impairment review using prices that reflect an average of the trailing 12-month prices as prescribed pursuant to the SEC’s guidelines and did not incur a full-cost ceiling test impairment charge. The average prices used in the March 31, 2020 impairment review are significantly higher than the actual and currently forecasted prices in 2020. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of our future net revenues is expected to decline and a full-cost ceiling impairment charge is expected to be recognized. We expect we will be required to record an impairment charge on our oil and natural gas properties in the second quarter of 2020. This impairment charge would be non-cash in nature and should not impact any covenants under our various debt instruments. See Note 3 to our condensed financial statements.

If the unweighted arithmetic average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended March 31, 2020 had been $45.87 per Bbl and $2.07 per MMBtu, respectively, while all other factors remained constant, our oil and natural gas properties would have been impaired in excess of approximately $600.0 million on a pro forma basis. The aforementioned pro forma prices, as estimated for the twelve month period July 2019 through June 2020, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the 11 months ended May 2020, with the price for May 2020 being held constant for June 2020. This calculation of the impact of lower commodity prices on our estimated total proved oil and natural gas reserves and our full-cost ceiling was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our full-cost ceiling and proved reserves. The impact of prices is only one of several variables in the estimation of our proved reserves and full-cost ceiling and other factors could have a significant impact on our future proved reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, acquisitions of proved reserves, changes in drilling and completion and operating costs, drilling results, revisions due to well performance and other factors, changes in development plans and production, among others. There are numerous uncertainties inherent in the estimation of proved oil and natural gas reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

In response to the COVID-19 pandemic, we have instituted various measures to protect our workforce and our business operations, such as remote working and business travel restrictions. As a non-operator with no field operations, substantially all of our employees’ work can be completed from home. We will continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to make decisions aimed at protecting and furthering the interests of all stakeholders.



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Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

Oil price differentials.  The price differential between our Williston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, pipeline or truck to refineries.

Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil.  Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end.

Production expenses.  Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.  We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions.  In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depreciation, depletion, amortization and impairment.  Depreciation, depletion, amortization and impairment includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method.

General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.

Interest expense.  We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings.  As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.  We capitalize a portion of the interest paid on applicable borrowings into our full cost pool.  We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.

Income tax expense.  Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.






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Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

the timing and success of drilling and production activities by our operating partners;

the prices and the supply and demand for oil, natural gas and NGLs;

the quantity of oil and natural gas production from the wells in which we participate;

changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;

our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of our acreage and wells in the Williston Basin subjects our operating results to factors specific to this region.  These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region.

The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market.  Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of oil; however, because of the Williston Basin’s location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs.  While rail transportation has historically been more expensive than pipeline transportation, Williston Basin’s prices have at times justified shipment by rail to markets across the United States. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region, specifically the Dakota Access Pipeline which has given the region low-cost transportation with access to Gulf Coast markets, which generally have higher benchmark pricing than WTI prices, offsetting some of the cost for the mode of transportation.

The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price.  Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the first quarter of 2020 was $8.50 per barrel, as compared to $6.19 per barrel in the first quarter of 2019. Fluctuations in our oil price differential are due to several factors such as takeaway capacity relative to production levels in the Williston Basin and seasonal refinery maintenance temporarily depressing crude demand.

Another significant factor affecting our operating results is drilling costs.  The cost of drilling wells can vary significantly, driven in part by volatility in oil prices that can substantially impact the level of drilling activity in the Williston Basin.  Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher.  Lower oil prices have generally had the opposite effect.  In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant.  During the first three months of 2020, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was $7.6 million, compared to $8.0 million for the wells we elected to participate in during 2019.

Market Conditions

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand.  Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.  World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices.  Historically, commodity prices have been volatile and we expect the volatility to continue in the future.  Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.


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During the first quarter of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63 per Bbl in early January to just above $20 per Bbl in late March. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. At April 29, 2020, the NYMEX WTI oil futures contract for the earliest delivery date had decreased significantly from the average price for the first quarter of 2020, settling at $15.06 per Bbl. The general outlook for the oil and natural gas industry for the remainder of 2020 remains highly uncertain, and we can provide no assurances as to when the economic disruptions resulting from COVID-19 and the corresponding decline in oil demand may begin to improve. Until such time, however, we anticipate that oil prices will remain well below the prices realized in 2019. See “Risk Factors” in Part II, Item 1A below for additional information.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three months ended March 31, 2020 and 2019.

  Three Months Ended March 31,
  2020 2019
Average NYMEX Prices(1)
   
Natural Gas (per Mcf) $ 1.91    $ 2.93   
Oil (per Bbl) $ 45.57    $ 54.87   
__________
(1)Based on average NYMEX closing prices.

For the three months ended March 31, 2020, the average NYMEX pricing was $45.57 per barrel of oil or 17% lower than the average NYMEX price per barrel for the comparable period in 2019.  Our realized oil price after reflecting settled derivatives was 12% lower in the first quarter of 2020 than in the first quarter of 2019 due to the aforementioned lower average NYMEX price per barrel and a higher oil price differential.

As of March 31, 2020, we had a total volume on open commodity price swaps of 15.1 million barrels at a weighted average price of approximately $56.45 per barrel (see Note 11 to the condensed financial statements).
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Results of Operations for the Three Months Ended March 31, 2020 and March 31, 2019

The following table sets forth selected operating data for the periods indicated.
  Three Months Ended March 31,
2020 2019 % Change
Net Production:      
Oil (Bbl) 3,138,380    2,541,232    24  %
Natural Gas and NGLs (Mcf) 5,049,120    3,435,784    47  %
Total (Boe) 3,979,900    3,113,863    28  %
Net Sales (in thousands):      
Oil Sales $ 116,333    $ 123,613    (6) %
Natural Gas and NGL Sales 13,863    9,070    53  %
Gain (Loss) on Settled Commodity Derivatives 31,506    12,546    151  %
Gain (Loss) on Unsettled Commodity Derivatives 345,075    (152,169)   —  %
Other Revenue     —  %
Total Revenues 506,785    (6,934)   —  %
Average Sales Prices:      
Oil (per Bbl) $ 37.07    $ 48.64    (24) %
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Bbl) 10.04    4.94    —  %
Oil Net of Settled Commodity Derivatives (per Bbl) 47.11    53.58    (12) %
Natural Gas and NGLs (per Mcf) 2.75    2.64    %
Realized Price on a Boe Basis Including Settled Commodity Derivatives 40.63    46.64    (13) %
Operating Expenses (in thousands):      
Production Expenses $ 37,335    $ 24,666    51  %
Production Taxes 11,896    12,520    (5) %
General and Administrative Expenses 4,871    6,051    (19) %
Depletion, Depreciation, Amortization and Accretion 61,809    45,134    37  %
Costs and Expenses (per Boe):      
Production Expenses $ 9.38    $ 7.92    18  %
Production Taxes 2.99    4.02    (26) %
General and Administrative Expenses 1.22    1.94    (37) %
Depletion, Depreciation, Amortization and Accretion 15.53    14.49    %
Net Producing Wells at Period End 464.8    332.5    40  %

Oil and Natural Gas Sales

In the first quarter of 2020, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 2% as compared to the first quarter of 2019, driven by a 23% decrease in realized prices, excluding the eff