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EXCEL - IDEA: XBRL DOCUMENT - NORTHERN OIL & GAS, INC.Financial_Report.xls
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EX-32.1 - CERTIFICATION OF CEO AND CFO - NORTHERN OIL & GAS, INC.exhibit321_06302014.htm
EX-31.1 - CERTIFICATION OF CEO - NORTHERN OIL & GAS, INC.exhibit311_06302014.htm

 
 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


FORM 10-Q

 
 
x QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2014
 
 
o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT
 
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)

Minnesota
95-3848122
(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer Identification No.)

315 Manitoba Avenue – Suite 200
Wayzata, Minnesota 55391
(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)
 
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 x  No o
  
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer  x                                                                           Accelerated Filer  ¨

Non-Accelerated Filer    o                                                                           Smaller Reporting Company  o
   (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o No x
 
As of August 1, 2014, there were 61,027,961 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 oil, NGL and natural gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of 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 Boes.

Mcf.”  One thousand cubic feet of natural gas.

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

MMBoe.”  One million Boes.

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.
 
 
i

 

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

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 or injection rates 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 to the addition 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.
 
 
ii

 

 
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.

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.

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 (PDP’s).”  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 (PDNP’s). 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.
 
 
iii

 

 
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.

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 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.

(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 12-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.”  The estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, formerly Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.”


 
iv

 

NORTHERN OIL AND GAS, INC.
FORM 10-Q

June 30, 2014

C O N T E N T S

 
Page
PART I – FINANCIAL INFORMATION
 
   
Item 1.            Financial Statements (unaudited)
2
                        Balance Sheets
2
                        Statements of Comprehensive Income (Loss)
3
                        Statements of Cash Flows
4
                        Notes to Unaudited Condensed Financial Statements
5
   
Item 2.            Management’s Discussion and Analysis of Financial Condition and Results of Operations
21
   
Item 3.            Quantitative and Qualitative Disclosures about Market Risk
35
   
Item 4.            Controls and Procedures
37
   
PART II – OTHER INFORMATION
 
   
Item 1.            Legal Proceedings
39
   
Item 1A.         Risk Factors
39
   
Item 2.            Unregistered Sales of Equity Securities and Use of Proceeds
39
   
Item 6.            Exhibits
39
   



 
1

 

PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
JUNE 30, 2014 AND DECEMBER 31, 2013

   
June 30, 2014
(unaudited)
   
December 31, 2013
 
 CURRENT ASSETS
           
 Cash and Cash Equivalents
  $ 14,252,184     $ 5,687,166  
 Trade Receivables
    90,924,750       86,816,981  
 Advances to Operators
    855,736       618,786  
 Prepaid and Other Expenses
    1,735,379       770,740  
 Derivative Instruments
    -       62,890  
 Deferred Tax Asset
    20,436,000       10,431,000  
 Total Current Assets
    128,204,049       104,387,563  
                 
 PROPERTY AND EQUIPMENT
               
 Oil and Natural Gas Properties, Full Cost Method of Accounting
               
 Proved
    1,880,157,218       1,611,073,747  
 Unproved
    72,738,526       70,148,348  
 Other Property and Equipment
    1,766,997       1,701,366  
 Total Property and Equipment
    1,954,662,741       1,682,923,461  
 Less – Accumulated Depreciation and Depletion
    (363,735,124 )     (285,616,752 )
 Total Property and Equipment, Net
    1,590,927,617       1,397,306,709  
                 
 DERIVATIVE INSTRUMENTS
    -       1,745,405  
                 
 DEBT ISSUANCE COSTS
    15,050,983       16,160,283  
                 
 TOTAL ASSETS
  $ 1,734,182,649     $ 1,519,599,960  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 CURRENT LIABILITIES
               
 Accounts Payable
  $ 217,865,235     $ 168,936,785  
 Accrued Expenses
    3,016,337       2,645,178  
 Accrued Interest
    3,472,894       3,386,409  
 Derivative Instruments
    45,110,007       19,119,646  
 Total Current Liabilities
    269,464,473       194,088,018  
                 
 LONG-TERM LIABILITIES
               
 Revolving Credit Facility
    198,000,000       75,000,000  
 8% Senior Notes
    508,796,460       509,539,823  
 Derivative Instruments
    16,005,767       637,208  
 Other Noncurrent Liabilities
    4,428,584       3,832,550  
 Deferred Tax Liability
    128,029,000       116,674,000  
 Total Long-Term Liabilities
    855,259,811       705,683,581  
                 
 TOTAL LIABILITIES
    1,124,724,284       899,771,599  
                 
 COMMITMENTS AND CONTINGENCIES (NOTE 8)
               
                 
 STOCKHOLDERS’ EQUITY
               
 Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding
    -       -  
 Common Stock, Par Value $.001; 95,000,000 Authorized, 6/30/2014 – 61,029,679
   Shares Outstanding and 12/31/2013 – 61,858,199 Shares Outstanding
    61,030       61,858  
 Additional Paid-In Capital
    433,497,678       446,044,159  
 Retained Earnings
    175,899,657       173,722,344  
 Total Stockholders’ Equity
    609,458,365       619,828,361  
                 
 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 1,734,182,649     $ 1,519,599,960  
The accompanying notes are an integral part of these financial statements.

 
2

 

NORTHERN OIL AND GAS, INC.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013
(UNAUDITED)


   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
 REVENUES
                       
 Oil and Gas Sales
  $ 121,155,047     $ 79,623,169     $ 217,958,016     $ 162,794,830  
 Loss on Settled Derivatives
    (11,248,770 )     (498,817 )     (18,066,750 )     (870,100 )
 (Losses) Gains on the Mark-to-Market of Derivative Instruments
    (35,307,533 )     17,009,668       (43,167,216 )     2,099,013  
 Other Revenue
    3,269       27,783       3,269       36,142  
 Total Revenues
    74,602,013       96,161,803       156,727,319       164,059,885  
                                 
 OPERATING EXPENSES
                               
 Production Expenses
    13,033,322       10,397,171       24,710,750       19,038,381  
 Production Taxes
    12,213,387       7,561,156       22,004,588       15,372,460  
 General and Administrative Expense
    3,980,819       3,915,298       7,978,509       7,904,104  
 Depletion, Depreciation, Amortization and Accretion
    42,212,250       26,559,126       78,313,171       53,351,819  
 Total Expenses
    71,439,778       48,432,751       133,007,018       95,666,764  
                                 
 INCOME FROM OPERATIONS
    3,162,235       47,729,052       23,720,301       68,393,121  
                                 
 OTHER INCOME (EXPENSE)
                               
 Interest Expense, Net of Capitalization
    (10,326,789 )     (7,819,591 )     (20,225,758 )     (13,927,591 )
 Other Income (Expense)
    2,104       (267,788 )     32,771       (267,724 )
 Total Other Income (Expense)
    (10,324,685 )     (8,087,379 )     (20,192,987 )     (14,195,315 )
                                 
 INCOME BEFORE INCOME TAXES
    (7,162,450 )     39,641,673       3,527,314       54,197,806  
                                 
 INCOME TAX PROVISION (BENEFIT)
    (2,750,000 )     14,630,000       1,350,000       20,234,614  
                                 
 NET INCOME (LOSS)
  $ (4,412,450 )   $ 25,011,673     $ 2,177,314     $ 33,963,192  
                                 
 COMPREHENSIVE INCOME (LOSS)
  $ (4,412,450 )   $ 25,011,673     $ 2,177,314     $ 33,963,192  
                                 
 Net Income (Loss) Per Common Share – Basic
  $ (0.07 )   $ 0.40     $ 0.04     $ 0.54  
 Net Income (Loss) Per Common Share – Diluted
  $ (0.07 )   $ 0.39     $ 0.04     $ 0.54  
 Weighted Average Shares Outstanding – Basic
    60,504,781       62,973,916       60,852,322       62,915,941  
 Weighted Average Shares Outstanding – Diluted
    60,504,781       63,358,152       61,059,485       63,337,342  
                           
The accompanying notes are an integral part of these financial statements.



 
3

 

NORTHERN OIL AND GAS, INC.
STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2014 AND 2013
(UNAUDITED)
 

   
Six Months Ended
 
   
June 30,
 
   
2014
   
2013
 
 CASH FLOWS FROM OPERATING ACTIVITIES
           
 Net Income
  $ 2,177,314     $ 33,963,192  
 Adjustments to Reconcile Net Income to Net Cash Provided by
 Operating Activities:
               
 Depletion, Depreciation, Amortization and Accretion
    78,313,171       53,351,819  
 Amortization of Debt Issuance Costs
    1,344,235       1,160,880  
 Amortization of Senior Unsecured Notes Premium
    (743,363 )     (216,814 )
 Deferred Income Taxes
    1,350,000       20,230,000  
 (Gain) Loss on the Mark-to-Market of Derivative Instruments
    43,167,216       (2,099,013 )
 Amortization of Deferred Rent
    (7,328 )     (7,327 )
 Share-Based Compensation Expense
    1,132,716       2,307,870  
 Changes in Working Capital and Other Items:
               
 Trade Receivables
    (4,107,769 )     648,479  
 Prepaid Expenses and Other
    (964,639 )     (524,530 )
 Accounts Payable
    6,859,505       669,303  
 Accrued Interest
    (1,718 )     1,152,917  
 Accrued Expenses
    371,159       (200,343 )
 Net Cash Provided By Operating Activities
    128,890,499       110,436,433  
                 
 CASH FLOWS FROM INVESTING ACTIVITIES
               
 Purchases of Oil and Natural Gas Properties and Development Capital Expenditures
    (228,850,417 )     (187,242,287 )
 Proceeds from Sale, Net of Oil and Natural Gas Properties
    -       908,000  
 Purchases of Other Property and Equipment
    (65,631 )     (88,707 )
 Net Cash Used For Investing Activities
    (228,916,048 )     (186,422,994 )
                 
 CASH FLOWS FROM FINANCING ACTIVITIES
               
 Advances on Revolving Credit Facility
    123,000,000       58,000,000  
 Repayments on Revolving Credit Facility
    -       (182,000,000 )
 Issuance of Senior Unsecured Notes
    -       210,500,000  
 Debt Issuance Costs Paid
    (234,936 )     (5,757,875 )
 Repurchase of Common Stock
    (14,174,497 )     (48,125 )
 Net Cash Provided by Financing Activities
    108,590,567       80,694,000  
                 
 NET INCREASE IN CASH AND CASH EQUIVALENTS
    8,565,018       4,707,439  
                 
 CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD
    5,687,166       13,387,998  
                 
 CASH AND CASH EQUIVALENTS – END OF PERIOD
  $ 14,252,184     $ 18,095,437  
                 
 Supplemental Disclosure of Cash Flow Information
               
 Cash Paid During the Period for Interest
  $ 21,828,667     $ 14,246,467  
 Cash Paid During the Period for Income Taxes
  $ -     $ 13,614  
                 
 Non-Cash Financing and Investing Activities:
               
 Oil and Natural Gas Properties Included in Accounts Payable
  $ 204,953,165     $ 103,674,079  
 Capitalized Asset Retirement Obligations
  $ 408,563     $ 266,451  
 Non-Cash Compensation Capitalized on Oil and Gas Properties
  $ 494,471     $ 1,047,367  
                 
The accompanying notes are an integral part of these financial statements.


 
4

 

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
JUNE 30, 2014
(Unaudited)

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Minnesota 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 MKT market under the symbol “NOG”.

Northern’s principal business is crude oil and natural gas exploration, development, and production with operations in North Dakota and Montana 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.  As of June 30, 2014, approximately 60% of Northern’s 186,695 total net acres were developed.


NOTE 2     SIGNIFICANT ACCOUNTING POLICIES

The financial information included herein is unaudited, except for the balance sheet as of December 31, 2013, which has been derived from the Company’s audited financial statements for the year ended December 31, 2013.  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 omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2013, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

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 reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, and deferred income taxes.  Actual results may differ from those estimates.

Cash and Cash Equivalents

Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents.  Cash equivalents consist primarily of interest-bearing bank accounts and money market funds.  The Company’s cash positions represent assets held in checking and money market accounts.  These assets are generally available on a daily or weekly basis and are highly liquid in nature.  Due to the balances being greater than $250,000, the Company does not have FDIC coverage on the entire amount of bank deposits.  The Company believes this risk is minimal.  In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets.


 
5

 


Accounts Receivable

Accounts receivable are carried on a gross basis, with no discounting.  The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances.
 
The allowance for doubtful accounts at June 30, 2014 and December 31, 2013 was $2,115,000 and $1,050,000, respectively.

Advances to Operators

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners.  Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs.  The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.

Other Property and Equipment

Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years.  Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets.  Depreciation expense was $80,086 and $92,867 for the three months ended June 30, 2014 and 2013, respectively.  Depreciation expense was $159,754 and $187,142 for the six months ended June 30, 2014 and 2013, respectively.

Full Cost Method

Northern 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 the production, general corporate overhead or similar activities.  Costs associated with production and general corporate activities are expensed in the period incurred.  Capitalized costs are summarized as follows for the three and six months ended June 30, 2014 and 2013, respectively.

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
Capitalized Certain Payroll and Other Internal Costs
  $ 347,689     $ 721,554     $ 996,565     $ 1,362,450  
Capitalized Interest Costs
    1,141,381       1,543,618       2,338,791       2,928,776  
      Total
  $ 1,489,070     $ 2,265,172     $ 3,335,356     $ 4,291,226  

As of June 30, 2014, the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.  There were no property sales in the six months ended June 30, 2014 and 2013.

Capitalized costs associated with impaired properties 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 based on the estimated gross proved reserves as determined by independent petroleum engineers.  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 June 30, 2014 and 2013, the Company transferred into the full cost pool costs related to expired leases of $4.9 million and $4.1 million, respectively.  For the six months ended June 30, 2014 and 2013, the Company transferred into the full cost pool costs related to expired leases of $12.2 million and $8.0 million, respectively.
 
 
6

 

 
Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects).  Should capitalized costs exceed this ceiling, impairment is recognized.  The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.  Such present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet.  Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.  For the six months ended June 30, 2014 and 2013, the Company did not realize any impairment of its properties.

Asset Retirement Obligations

Asset retirement obligation is included in other noncurrent liabilities and relates to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition.  Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

Debt Issuance Costs

Deferred financing costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes.  These debt issuance costs are being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4).

The amortization of debt issuance costs for the three months ended June 30, 2014 and 2013 was $709,644 and $654,693, respectively.  The amortization of debt issuance costs for the six months ended June 30, 2014 and 2013 was $1,344,235 and $1,160,880, respectively.

Bond Premium on Senior Notes

At June 30, 2014, the Company had recorded a bond premium of $10.5 million in connection with the “8% Senior Notes Due 2020” (see Note 4).  This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.

The amortization of the bond premium for the three months ended June 30, 2014 and 2013 was $371,681 and $216,814, respectively.  The amortization of the bond premium for the six months ended June 30, 2014 and 2013 was $743,363 and $216,814, respectively.

Revenue Recognition

The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.  The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.  For the six months ended June 30, 2014 and 2013, 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.

 
7

 


Concentrations of Market and Credit Risk

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, 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 from purchasers of its crude oil and natural gas production.  While certain of these customers 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 has been and will continue to be immaterial to the Company’s results of operations over the long-term.

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 customers 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.

Stock-Based Compensation

The Company records expense associated with the fair value of stock-based compensation.  For fully vested stock and restricted stock grants the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant.  For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.

Stock Issuance

The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.

Income Taxes

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.  No valuation allowance has been recorded as of June 30, 2014 and December 31, 2013.

Net Income Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options and restricted stock.  The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
 
 
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The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2014 and 2013 are as follows:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
Weighted Average Common Shares Outstanding – Basic
    60,504,781       62,973,916       60,852,322       62,915,941  
Plus: Potentially Dilutive Common Shares
                               
Stock Options and Restricted Stock
    -       384,236       207,163       421,401  
Weighted Average Common Shares Outstanding – Diluted
    60,504,781       63,358,152       61,059,485       63,337,342  
                                 
Restricted Stock Excluded from EPS due to the Anti-Dilutive Effect
    180,929       3,786       6,998       10,565  

As of June 30, 2014 and 2013, potentially dilutive shares from stock options were 141,872 and 251,963, respectively.

Derivative Instruments and Price Risk Management

The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil.  The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.

All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.  Any realized gains and losses are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to gains (losses) on the mark-to-market of derivative instruments on the statements of comprehensive income (loss).  See Note 12 for a description of the derivative contracts which the Company has entered into.

Impairment
 
Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Crude oil and natural gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules.  There was no impairment recorded for the six months ended June 30, 2014 and 2013.
 
New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date.  If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition.  The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This guidance will be effective for the Company in the annual period beginning after December 15, 2016.  The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company’s statement of comprehensive income (loss), balance sheets, cash flows or disclosures.



 
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NOTE 3     CRUDE OIL AND NATURAL GAS PROPERTIES

The 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 statements of comprehensive income (loss) from the closing date of the acquisition.  Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition.  In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.  Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at June 30, 2014 and December 31, 2013 were approximately $205.0 million and $163.0 million, respectively.

Acquisitions

For the six months ended June 30, 2014, the Company acquired approximately 11,681 net acres, for an average cost of approximately $1,671 per net acre, in its key prospect areas in the form of effective leases.  During the same period, the Company separately acquired working interests in 74 gross (6.2 net) wells in undrilled locations in which it does not hold the underlying leasehold interests, for a total cost of approximately $6.6 million.

For the six months ended June 30, 2013, the Company acquired approximately 10,497 net acres, for an average cost of approximately $1,075 per net acre, in its key prospect areas in the form of effective leases.

Unproved Properties

Unproved properties not being amortized comprise approximately 59,500 net acres and 60,600 net acres of undeveloped leasehold interests at June 30, 2014 and December 31, 2013, respectively.  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.

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 its properties by purchasing individual or small groups of leases directly from mineral owners or from 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.


NOTE 4     REVOLVING CREDIT FACILITY AND LONG-TERM DEBT

Revolving Credit Facility

In February 2012, the Company entered into an amended and restated credit agreement providing for a revolving credit facility (the “Revolving Credit Facility”), which replaced its previous revolving credit facility with a syndicated facility.  The Revolving Credit Facility, which is secured by substantially all of the Company’s assets, provides for a commitment equal to the lesser of the facility amount or the borrowing base.  At June 30, 2014, the facility amount was $750 million, the borrowing base was $500 million and there was a $198 million outstanding balance, leaving $302 million of borrowing capacity available under the facility.  Under the terms of the Revolving Credit Facility, the Company may issue an unlimited amount of permitted additional indebtedness, as defined, provided that the borrowing base will be reduced by 25% of the stated amount of any such permitted additional indebtedness.  The $500 million in Notes described below is “permitted additional indebtedness” as defined in the Revolving Credit Facility.


 
10

 


The Revolving Credit Facility matures on September 30, 2018 and provides for a borrowing base subject to redetermination semi-annually each April and October and for event-driven unscheduled redeterminations.  Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.5% to 1.5% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined) plus a spread ranging from 1.5% to 2.5%.  The applicable spread at any time is dependent upon the amount of borrowings relative to the borrowing base at such time.  The Company may elect, from time to time, to convert all or any part of its LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans.  A commitment fee is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50%.  At June 30, 2014, the commitment fee was 0.375% and the interest rate margin was 1.75% on LIBOR loans and 0.75% on base rate loans.

The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of its business or operations, merge, consolidate, or make investments.  In addition, the Company is required to maintain a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0.

All of the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in any and all assets of the Company.

8.000% Senior Notes Due 2020

On May 18, 2012, the Company issued at par value $300 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “Original Notes”).  On May 13, 2013, the Company issued at a price of 105.25% an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “Follow-on Notes” and, together with the Original Notes, the “Notes”).  Interest is payable on the Notes semi-annually in arrears on each of June 1 and December 1.  The Company currently does not have any subsidiaries and, as a result, the Notes are not currently guaranteed.  Any subsidiaries the Company forms in the future may be required to unconditionally guarantee, jointly and severally, payment obligation under the Notes on a senior unsecured basis.  The issuance of the Original Notes resulted in net proceeds to the Company of approximately $291.2 million and the issuance of the Follow-on Notes resulted in net proceeds to the Company of approximately $200.1 million, which are in use to fund the Company’s exploration, development and acquisition program and for general corporate purposes (including repayment of borrowings that were outstanding under the Revolving Credit Facility at the time the Notes were issued).
 
At any time prior to June 1, 2015, the Company may redeem up to 35% of the Notes at a redemption price of 108% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption.  Prior to June 1, 2016, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.  On and after June 1, 2016, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104% for the twelve-month period beginning on June 1, 2016, 102% for the twelve-month period beginning June 1, 2017 and 100% beginning on June 1, 2018, plus accrued and unpaid interest to the redemption date.

The Notes are governed by an Indenture (the “Indenture”), dated as of May 18, 2012, by and among the Company and Wilmington Trust, National Association, as trustee (the “Trustee”).

The Indenture restricts the Company’s ability to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or, repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets.  These covenants are subject to a number of important exceptions and qualifications.  If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries (if any) will cease to be subject to such covenants.
 
 
11

 

 
The Indenture contains customary events of default, including:
 
·  
default in any payment of interest on any Note when due, continued for 30 days;
 
·  
default in the payment of principal of or premium, if any, on any Note when due;
 
·  
failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;
 
·  
payment defaults and accelerations with respect to other indebtedness of the Company and certain of its subsidiaries, if any, in the aggregate principal amount of $25 million or more;
 
·  
certain events of bankruptcy, insolvency or reorganization of the Company or a significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary;
 
·  
failure by the Company or any significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary to pay certain final judgments aggregating in excess of $25 million within 60 days; and
 
·  
any guarantee of the Notes by a guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.


NOTE 5    COMMON AND PREFERRED STOCK

The Company’s Articles of Incorporation authorize the issuance of up to 100,000,000 shares.  The shares are classified in two classes, consisting of 95,000,000 shares of common stock, par value $.001 per share, and 5,000,000 shares of preferred stock, par value $.001 per share.  The board of directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series.  The Company has neither designated nor issued any shares of preferred stock.

Common Stock

The following is a schedule of changes in the number of shares of common stock during the six months ended June 30, 2014 and the year ended December 31, 2013:

   
Six Months Ended
June 30, 2014
   
Year Ended
December 31, 2013
 
Beginning Balance
    61,858,199       63,532,622  
Stock-Based Compensation
    -       57,371  
Stock Options Exercised
    100,000       10,091  
Restricted Stock Grants (Note 6)
    156,960       353,596  
Stock Repurchased
    (1,018,897 )     (2,036,383 )
Other Surrenders
    (66,583 )     (59,098 )
Ending Balance
    61,029,679       61,858,199  

2014 Activity

In the six months ended June 30, 2014, 30,957 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 $457,000, which was based on the market price on the date the shares were surrendered.

In the six months ended June 30, 2014, a former director of the Company exercised an aggregate of 100,000 stock options, which were granted in 2007.  Of those stock options, 35,626 shares were surrendered to cover the aggregate exercise price of approximately $518,000, based on the market price on the date the shares were surrendered.

Stock Repurchase Program
 
In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150 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.


 
12

 


During the first quarter of 2014, the Company repurchased 1,018,897 shares of its common stock under the stock repurchase program. These shares are now included in the Company’s pool of authorized but unissued shares.  This stock had a cost of approximately $13.7 million.  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.

Performance Equity Awards

In early 2014, certain of the Company’s executive officers were granted performance equity awards under the 2014 long-term equity incentive program adopted by the compensation committee.  Entitlement to the performance shares will be based on the Company’s 2014 performance relative to established performance goals for proved reserve growth, debt-adjusted proved reserve value per share and year-over-year growth in average stock price relative to a selected peer group.  Participants may earn from zero to 180 percent of their 2014 base salaries and the amounts earned will be settled in restricted shares of common stock that will vest annually over a subsequent three-year service-based vesting period beginning in 2015.  The maximum dollar amount of the performance shares issuable if all participants earned the maximum award would total $3.0 million.  For the three and six month period ended June 30, 2014, the Company has recorded $0.2 million and $0.3 million, respectively, of compensation expense in connection with these performance equity awards.  No such performance equity awards have vested.


NOTE 6     STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS

On April 5, 2013, the board of directors approved the Company’s 2013 Incentive Plan (the “2013 Plan”), which was subsequently approved at the 2013 annual meeting of shareholders.  1,500,000 shares were authorized for grant under the 2013 Plan, plus the number of shares remaining available for future grants under the Company’s predecessor 2009 Equity Incentive Plan on the date the shareholders approved the 2013 Plan.  The 2013 Plan is intended to provide a means whereby the Company may be able, by granting equity and other types of awards, to attract, retain and motivate capable and loyal employees, non-employee directors, consultants and advisors of the Company, for the benefit of the Company and its shareholders.

Restricted Stock Awards

During the six months ended June 30, 2014, the Company issued 156,960 restricted shares of common stock under the 2013 Plan as compensation to officers, employees and directors of the Company.  Unvested restricted shares vest over various terms with all restricted shares vesting no later than April 2017.  As of June 30, 2014, there was approximately $6.0 million of total unrecognized compensation expense related to unvested restricted stock.  This compensation expense will be recognized over the remaining vesting period of the grants.  The Company has assumed a zero percent forfeiture rate for restricted stock due to the small number of officers, employees and directors that have received restricted stock awards.

The following table reflects the outstanding restricted stock awards and activity related thereto for the six months ended June 30, 2014:

   
Six Months Ended
June 30, 2014
 
   
Number of
Shares
   
Weighted-Average
Price
 
Restricted Stock Awards:
           
Restricted Shares Outstanding at Beginning of Period
    592,565     $ 16.84  
Shares Granted
    156,960       14.08  
Lapse of Restrictions
    (243,951 )     17.91  
Restricted Shares Outstanding at End of Period
    505,574     $ 15.46  


 
13

 


Stock Option Awards

On November 1, 2007, the board of directors granted options to purchase 560,000 shares of the Company’s common stock under the Company’s 2006 Incentive Stock Option Plan.  The Company granted options to purchase 500,000 shares of the Company’s common stock, to members of the board and options to purchase 60,000 shares of the Company’s common stock to one employee pursuant to an employment agreement.  These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date.  As of June 30, 2014, options to purchase a total of 141,872 shares of the Company’s common stock remain outstanding but unexercised.  The board of directors determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan.

The Company used the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  The Company used the simplified method to determine the expected term of the options due to the lack of sufficient historical data.  Changes in these assumptions can materially affect the fair value estimate.  The total fair value of the options was recognized as compensation over the vesting period.  There were no stock options granted by the Company in the six months ended June 30, 2014.

Currently Outstanding Options

·  
No options were forfeited during the six months ended June 30, 2014.
·  
No options expired during the six months ended June 30, 2014.
·  
Options covering 141,872 shares were exercisable and outstanding at June 30, 2014.
·  
The Company recorded no compensation expense related to these options for the six months ended June 30, 2014.  There is no further compensation expense that will be recognized in future periods relative to any options that had been granted as of June 30, 2014, because the Company recognized the entire fair value of such compensation upon vesting of the options.
·  
There were no unvested options at June 30, 2014.


NOTE 7     RELATED PARTY TRANSACTIONS

The Company is a non-operating participant in a number of wells in North Dakota that are operated by Emerald Oil, Inc. (“Emerald”), by virtue of leased acreage held by the Company in drilling units operated by Emerald.  As of June 30, 2014, such wells included 26 gross (5.6 net) producing wells, and an additional 9 gross (1.1 net) wells that were drilling or awaiting completion.  Based on authorizations for expenditure (or AFEs) provided by Emerald with respect to each of the wells, the total drilling and completion costs for these 35 gross wells was estimated at approximately $358 million, approximately $67 million of which is attributable to Northern Oil’s working interest in the wells.  James Russell (J.R.) Reger is a director, executive officer and less than 5% shareholder of Emerald, which is a publicly-traded company.  J.R. Reger is also the brother of Northern Oil’s Chairman and Chief Executive Officer, Michael Reger.  At June 30, 2014, the Company’s accounts receivable and accounts payable balances with Emerald were $4.1 million and $16.6 million, respectively.  At December 31, 2013, the Company’s accounts receivable and accounts payable balances with Emerald were $4.6 million and $23.2 million, respectively.  The Company recorded total revenues of $12.75 million and $0 from Emerald for the six months ended June 30, 2014 and 2013, respectively.

All transactions involving related parties are approved or ratified by the Company’s Audit Committee.


NOTE 8     COMMITMENTS & CONTINGENCIES

Litigation

The Company is engaged in 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 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.
 
14

 
 
The Company is party to a quiet title action in North Dakota that relates to its interest in certain crude oil and natural gas leases.  In the event the action results in a final judgment that is adverse to the Company, the Company would be required to reverse approximately $1.6 million in revenue (net of accrued taxes) that has been accrued since the second quarter of 2008 based on the Company’s purported interest in the crude oil and natural gas leases at issue, $0.1 million of which relates to the six month period ended June 30, 2014.  The Company fully maintains the validity of its interest in the crude oil and natural gas leases, and is vigorously defending such interest.


NOTE 9     INCOME TAXES

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.  Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

The income tax provision (benefit) for the three and six months ended June 30, 2014 and 2013 consists of the following:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
Current Income Taxes
  $ -     $ -     $ -     $ 4,614  
Deferred Income Taxes
                               
         Federal
    (2,506,000 )     13,874,000       1,235,000       18,969,000  
         State
    (244,000 )     756,000       115,000       1,261,000  
Total Provision (Benefit)
  $ (2,750,000 )   $ 14,630,000     $ 1,350,000     $ 20,234,614  

Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement.  Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.

The Company has no liabilities for unrecognized tax benefits.

The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the three and six months ended June 30, 2014 and 2013, the Company did not recognize any interest or penalties in its statements of comprehensive income (loss), nor did it have any interest or penalties accrued in its balance sheet at June 30, 2014 and December 31, 2013 relating to unrecognized benefits.

The tax years 2013, 2012, 2011 and 2010 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.


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:


 
15

 


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 of 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.

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of June 30, 2014 and December 31, 2013.

   
Fair Value Measurements at
June 30, 2014 Using
 
   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Commodity Derivatives – Current Liability (crude oil swaps and collars)
  $ -     $ (45,110,007 )   $ -  
Commodity Derivatives – Non-Current Liability (crude oil swaps)
    -       (12,389,078 )     -  
Commodity Derivatives – Non-Current Liability (crude oil swaptions)
    -       (3,616,689 )     -  
Total
  $ -     $ (61,115,774 )   $ -  

   
Fair Value Measurements at
December 31, 2013 Using
 
   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Commodity Derivatives – Current Asset (crude oil swaps and collars)
  $ -     $ 62,890     $ -  
Commodity Derivatives – Current Liability (crude oil swaps and collars)
    -       (19,119,646 )     -  
Commodity Derivatives – Non-Current Asset (crude oil swaps)
    -       1,745,405       -  
Commodity Derivatives – Non-Current Liability (crude oil swaps)
    -       (637,208 )     -  
Total
  $ -     $ (17,948,559 )   $ -  

Level 2 assets and liabilities consist of derivative assets and liabilities (see Note 12), the Revolving Credit Facility (see Note 4) and the Notes (see Note 4).  The fair value of the Company’s derivative financial 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 all derivative contracts is reflected on the balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.  The book value of the Revolving Credit Facility approximates fair value because of its floating rate structure.  The fair value of our Notes is based on an end of period market quote.


 
16

 


The Company’s long-term debt is not measured at fair value on the balance sheets and the fair value is being provided for disclosure purposes.  At June 30, 2014, the Company had $500 million of senior unsecured notes and $198 million under the Revolving Credit Facility outstanding with a fair value of $536.3 million and $198 million, respectively.  At December 31, 2013, the Company had $500 million of senior unsecured notes and $75 million under the Revolving Credit Facility outstanding with a fair value of $527.5 million and $75 million, respectively.  The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to the Company at the end of each respective period.

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 six month period ended June 30, 2014.


NOTE 11     FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents and credit facility and are not measured at fair value on the balance sheets.  The carrying amount of these non-derivative financial instruments approximate their fair values (see Note 10).

The Company’s accounts receivable relate to crude oil and natural gas sold to various industry companies.  Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral.  Management believes the Company’s accounts receivable at June 30, 2014 and December 31, 2013 do not represent significant credit risks as they are dispersed across many counterparties.  The Company has recorded an allowance for doubtful accounts of $2.1 million and $1.1 million at June 30, 2014 and December 31, 2013, respectively.  As of June 30, 2014, outstanding derivative contracts with commercial banks participating in the Company’s Revolving Credit Facility represent all of the Company’s crude oil volumes hedged.  These commercial banks have investment-grade ratings from Moody’s and Standard & Poor and are lenders under the Company’s Revolving Credit Facility and management believes this does not represent a significant credit risk.


NOTE 12     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity swap contracts, swaptions and costless 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.

All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.  Any realized gains and losses are recorded to loss on settled derivatives and unrealized gains or losses are recorded to losses on the mark-to-market of derivative instruments on the statement of comprehensive income (loss).

The Company has master netting agreements on individual crude oil contracts 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.


 
17

 


Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges

The Company recorded realized losses on settled derivatives of $11,248,770 and $498,817 in the statement of comprehensive income (loss) for the three months ended June 30, 2014 and 2013, respectively.  The Company recorded a loss of $35,307,533 and a gain of $17,009,668 on the mark-to-market of derivative instruments in the statement of comprehensive income (loss) for the three months ended June 30, 2014 and 2013, respectively.  The Company recorded realized losses on settled derivatives of $18,066,750 and $870,100 in the statement of comprehensive income (loss) for the six months ended June 30, 2014 and 2013, respectively.  The Company recorded a loss of $43,167,216 and a gain of $2,099,013 on the mark-to-market of derivative instruments in the statement of comprehensive income (loss) for the six months ended June 30, 2014 and 2013, respectively.
 
The following table reflects open commodity swap contracts as of June 30, 2014, the associated volumes and the corresponding fixed price.

Settlement Period
 
Oil (Barrels)
   
Fixed Price
 
Swaps-Crude Oil
           
07/01/14 – 12/31/14
    120,000       91.65  
07/01/14 – 12/31/14
    232,500       88.55  
07/01/14 – 12/31/14
    232,500       88.60  
07/01/14 – 12/31/14
    232,500       88.40  
07/01/14 – 12/31/14
    232,500       88.50  
07/01/14 – 12/31/14
    60,000       91.35  
07/01/14 – 12/31/14
    60,000       90.00  
07/01/14 – 12/31/14
    120,000       90.15  
07/01/14 – 12/31/14
    120,000       91.00  
07/01/14 – 12/31/14
    60,000       93.00  
07/01/14 – 12/31/14
    120,000       90.00  
07/01/14 – 12/31/14
    120,000       90.00  
07/01/14 – 12/31/14
    120,000       93.50  
07/01/14 – 12/31/14
    30,000       90.58  
07/01/14 – 06/30/15
    420,000       89.15  
01/01/15 – 06/30/15
    60,000       90.50  
01/01/15 – 06/30/15
    180,000       88.55  
01/01/15 – 06/30/15
    180,000       88.00  
01/01/15 – 06/30/15
    60,000       90.75  
01/01/15 – 06/30/15
    60,000       90.25  
01/01/15 – 06/30/15
    90,000       89.00  
01/01/15 – 06/30/15
    90,000       89.00  
01/01/15 – 12/31/15
    720,000       89.00  
01/01/15 – 12/31/15
    360,000       89.00  
01/01/15 – 12/31/15
    360,000       89.02  
01/01/15 – 12/31/15
    180,000       89.00  
01/01/15 – 12/31/15
    180,000       89.00  
07/01/15 – 12/31/15(1)
    180,000       90.75  
07/01/15 – 12/31/15(1)
    180,000       91.00  
07/01/15 – 12/31/15(1)
    180,000       91.25  
07/01/15 – 06/30/16
    360,000       89.00  
07/01/15 – 06/30/16
    360,000       90.00  
07/01/15 – 06/30/16
    360,000       91.00  
01/01/16 – 06/30/16
    180,000       90.00  
01/01/16 – 06/30/16
    90,000       90.00  
01/01/16 – 06/30/16
    90,000       90.00  
_________________
 
(1)
The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 90,000 barrels per month are exercisable on or about December 31, 2015.  If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 90,000 barrels per month at an average price of $91.00 per barrel for each month during the period January 1, 2016 through June 30, 2016.

As of June 30, 2014, the Company had a total volume on open commodity swaps of 6.8 million barrels at a weighted average price of approximately $89.61.


 
18

 


The following table reflects the weighted average price of open commodity swap derivative contracts as of June 30, 2014, by year with associated volumes.

Weighted Average Price
Of Open Commodity Swap Contracts
 
Year
 
Volumes (Bbl)
   
Weighted
Average Price
 
2014
    1,920,000     $ 89.79  
2015
    3,960,000       89.43  
2016
    900,000       90.00  

In addition to the open commodity swap contracts, the Company has entered into costless collar contracts.  The costless collars are used to establish floor and ceiling prices on anticipated crude oil production.  There were no premiums paid or received by the Company related to the costless collar contracts.  The following table reflects open costless collar contracts as of June 30, 2014.

Term
 
Oil (Barrels)
   
Floor/Ceiling Price
 
Basis
Costless Collars – Crude Oil
             
07/01/14 – 12/31/14
    120,000     $ 90.00/$99.05  
NYMEX

The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at June 30, 2014 and December 31, 2013, respectively.  Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement:

Type of Contract
 
Balance Sheet Location
 
June 30, 2014
Estimated
Fair Value
   
December 31, 2013 Estimated
Fair Value
 
Derivative Assets:
               
Swap Contracts
 
Current Assets
  $ -     $ 62,890  
Swap Contracts
 
Non-Current Assets
    -       1,745,405  
Total Derivative Assets
      $ -     $ 1,808,295  
                     
Derivative Liabilities:
                   
Swap Contracts
 
Current Liabilities
  $ (44,452,095 )   $ (19,111,820 )
Swap Contracts
 
Non-Current Liabilities
    (12,389,078 )     (637,208 )
Costless Collars
 
Current Liabilities
    (657,912 )     (7,826 )
Swaption Contracts
 
Non-Current Liabilities
    (3,616,689 )     -  
Total Derivative Liabilities
      $ (61,115,774 )   $ (19,756,854 )

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.

 
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Estimated Fair Value at June 30, 2014
 
   
Gross Amounts of Recognized Assets
   
Gross Amounts Offset in the Balance Sheet
   
Net Amounts of Assets Presented in the Balance Sheet
 
                   
Offsetting of Derivative Assets:
       
Current Assets
  $ -     $ -     $ -  
Non-Current Assets
    -       -       -  
Total Derivative Assets
  $ -     $ -     $ -  
                         
Offsetting of Derivative Liabilities:
         
Current Liabilities
  $ (45,110,007 )   $ -     $ (45,110,007 )
Non-Current Liabilities
    (16,005,767 )     -       (16,005,767 )
Total Derivative Liabilities
  $ (61,115,774 )   $ -     $ (61,115,774 )
                         

   
Estimated Fair Value at December 31, 2013
 
   
Gross Amounts of Recognized Assets
   
Gross Amounts Offset in the Balance Sheet
   
Net Amounts of Assets Presented in the Balance Sheet
 
                   
Offsetting of Derivative Assets:
       
Current Assets
  $ 629,178     $ (566,288 )   $ 62,890  
Non-Current Assets
    2,589,079       (843,674 )     1,745,405  
Total Derivative Assets
  $ 3,218,257     $ (1,409,962 )   $ 1,808,295  
                         
Offsetting of Derivative Liabilities:
         
Current Liabilities
  $ (19,685,934 )   $ 566,288     $ (19,119,646 )
Non-Current Liabilities
    (1,480,882 )     843,674       (637,208 )
Total Derivative Liabilities
  $ (21,166,816 )   $ 1,409,962     $ (19,756,854 )


 
20

 

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, and indebtedness covenant compliance 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,” “anticipate,” “target,” “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 Company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:  crude oil and natural gas prices, our ability to raise or access capital, general economic or industry conditions, nationally and/or in the communities in which our Company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, changes in accounting principles, policies or guidelines, financial or political instability, 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 actually achieved may differ materially from expected results described in these statements.  Forward-looking statements speak only as of the date they are made.  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, 2013, 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.  Our Company does not undertake, and specifically disclaims, 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 Financial Statements and Accompanying Notes 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.  We believe the location, size and concentration of our acreage position in one of North America’s leading unconventional oil-resource plays will provide drilling and development opportunities that result in significant long-term value.  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.

As of December 31, 2013, our proved reserves were 84.2 MMBoe (all of which were in the Williston Basin) as estimated by our third-party independent reservoir engineering firm, Ryder Scott Company, LP, which represents 25% growth in our proved reserves compared to year end 2012.  As of December 31, 2013, 42% of our reserves were classified as proved developed and 90% of our reserves were oil.


 
21

 


Our average daily production in the second quarter of 2014 was approximately 15,396 Boe per day, of which approximately 90% was oil.  Our second quarter 2014 average daily production increased 41% year-over-year, as compared to an average of 10,896 Boe per day in the second quarter of 2013.  As of June 30, 2014, we participated in 2,037 gross (165.2 net) producing wells.

As of June 30, 2014, we leased approximately 186,695 net acres, of which 100% were located in the Williston Basin of North Dakota and Montana.  During the six months ended June 30, 2014, we acquired approximately 11,681 net acres at an average cost of approximately $1,671 per net acre.  During the same period, we separately acquired working interests in 74 gross (6.2 net) wells in undrilled locations in which we do not hold the underlying leasehold interests, for a total cost of approximately $6.6 million.

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.  Our average realized price calculations include the effects of the settlement of all derivative contracts regardless of the accounting treatment.

Principal Components of Our Cost Structure

·  
Oil price differentials.  The price differential between our Williston Basin well head price and the New York Mercantile Exchange (“NYMEX”) WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, barge, pipeline or truck to refineries.

·  
(Loss) gain on the mark-to-market of derivative instruments.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil.  This account activity represents the recognition of gains and losses associated with our outstanding derivative contracts as commodity prices and commodity derivative contracts change on contracts that have not been designated for hedge accounting.

·  
Realized gain (loss) on settled derivatives.  This account activity represents our realized gains and losses on the settlement of commodity derivative instruments.

·  
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 and amortization.  Depreciation, depletion and amortization 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.


 
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·  
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.

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 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
 
·  
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 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 North Dakota’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 prices have been high enough to justify shipment by rail to markets such as St. James, Louisiana, which offer prices benchmarked to Brent/LLS.  Although pipeline, truck and rail capacity in the Williston Basin has historically lagged production in growth, we believe that additional planned infrastructure growth will help keep price discounts from significantly eroding wellhead values in the region.

The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price.  Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX WTI and the sales prices we receive for our oil production.  Our oil price differential to the NYMEX WTI benchmark price during the second quarter of 2014 was $12.25 per barrel, as compared to $5.32 per barrel in the second quarter of 2013.  Our oil price differential to the NYMEX WTI benchmark price during the first six months of 2014 was $12.65 per barrel, as compared to $4.47 per barrel in the first six months of 2013.


 
23

 


Over the past several years, oil production in the Williston Basin has increased dramatically.  For example, North Dakota’s oil production in October 2013 was up approximately 93% as compared to October 2011.  The surging oil production has created a huge need for oil takeaway infrastructure, which has struggled to keep pace with the growth in production.  This caused the price of Bakken crude to lag significantly behind NYMEX WTI crude at certain times over the last few years.  In response to rapidly rising production, rail capacity out of the area has greatly expanded, which has allowed Bakken crude to reach refining markets on the East Coast, West Coast and Gulf Coast.  As the takeaway solution developed, the Bakken crude differential to NYMEX WTI lowered in 2013, and even traded at points at a premium to NYMEX WTI.  During the second quarter of 2014, our weighted average oil price differential to the NYMEX WTI benchmark widened to approximately $12.25 per barrel due to several factors such as takeaway capacity lagging behind production, and seasonal refinery maintenance temporarily depressing crude demand.  As the rail capacity continues to increase and planned pipeline expansions are completed, we believe the oil price differentials will return to historical levels.  Our weighted average oil price differential to the NYMEX WTI benchmark price during 2013 was approximately $8.68 per barrel.

Another significant factor affecting our operating results is drilling costs.  The cost of drilling wells has increased significantly over the past few years as rising oil prices have triggered increased drilling activity in the Williston Basin. Although 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 choice of proppant (sand or ceramic), the total cost of drilling and completing an oil well has increased.  This increase is largely due to longer horizontal laterals and more fracture stimulation stages, but also higher demand for rigs and completion services throughout the region.  In addition, because of the rapid growth in drilling, the availability of well completion services has at times been constrained, resulting at times in a backlog of wells awaiting completion.

Market Conditions

Prices for various quantities of natural gas, natural gas liquids (“NGLs”) and oil that we produce significantly impact our revenues and cash flows.  Commodity prices have been volatile in recent years.  The following table lists average NYMEX prices for natural gas and oil for the three and six months ended June 30, 2014 and 2013.

   
Three Months Ended
June 30,
 
   
2014
   
2013
 
Average NYMEX Prices(a)
           
Natural Gas (per Mcf)
  $ 4.58     $ 4.02  
Oil (per Bbl)
  $ 102.99     $ 94.17  

   
Six Months Ended
June 30,
 
   
2014
   
2013
 
Average NYMEX Prices(a)
           
Natural Gas (per Mcf)
  $ 4.65     $ 3.76  
Oil (per Bbl)
  $ 100.84     $ 94.26  
________________
(a)  
Based on average NYMEX closing prices.


 
24

 


Results of Operations for the three month periods ended June 30, 2014 and June 30, 2013

The following table sets forth selected operating data for the periods indicated.

   
Three Months Ended
June 30,
 
   
2014
   
2013
   
% Change
 
Net Production:
                 
Oil (Bbl)
    1,260,310       895,005       41  
Natural Gas and NGLs (Mcf)
    844,279       579,346       46  
Total (Boe)
    1,401,023       991,563       41  
                         
Net Sales:
                       
Oil Sales
  $ 114,368,922     $ 76,570,408       49  
Natural Gas and NGL Sales
    6,786,125       3,052,761       122  
Loss on Settled Derivatives
    (11,248,770 )     (498,817 )     (2,155 )
Loss on the Mark-to-Market of Derivative Instruments
    (35,307,533 )     17,009,668       (308 )
Other Revenue
    3,269       27,783       (88 )
Total Revenues
    74,602,013       96,161,803       (22 )
                         
Average Sales Prices:
                       
Oil (per Bbl)
  $ 90.75     $ 85.55       6  
Effect of Loss on Settled Derivatives on Average Price (per Bbl)
    (8.93 )     (0.56 )     (1,495 )
Oil Net of Settled Derivatives (per Bbl)
    81.82       84.99       (4 )
Natural Gas and NGLs (per Mcf)
    8.04       5.27       53  
Realized Price on a Boe Basis Including all Realized Derivative Settlements
    78.45       79.80       (2 )
                         
Operating Expenses:
                       
Production Expenses
  $ 13,033,322     $ 10,397,171       25  
Production Taxes
    12,213,387       7,561,156       62  
General and Administrative Expense
    3,980,819       3,915,298       2  
Depletion, Depreciation, Amortization and Accretion
    42,212,250       26,559,126       59  
                         
Costs and Expenses (per Boe):
                       
Production Expenses
  $ 9.30     $ 10.49       (11 )
Production Taxes
    8.72       7.63       14  
General and Administrative Expense
    2.84       3.95       (28 )
Depletion, Depreciation, Amortization and Accretion
    30.13       26.79       13  
                         
Net Producing Wells at Period End
    165.2       121.5       36  

Oil and Natural Gas Sales

In the second quarter of 2014, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 52% as compared to the second quarter of 2013, driven by a 41% increase in production and a 9% increase in realized prices excluding the effect of settled derivatives.  The higher average realized price in the second quarter of 2014 as compared to the same period in 2013 was driven by higher average NYMEX oil prices.  Oil price differential during the second quarter of 2014 was $12.25 per barrel, as compared to $5.32 per barrel in the second quarter of 2013.

As discussed above, we add production through drilling success as we place new wells into production and through additions from acquisitions, partially offset by the natural decline of our oil and natural gas sales from existing wells.  During the second quarter of 2014, our production volumes increased 41% as compared to the second quarter of 2013.  Production primarily increased due to our continued addition of net producing wells.


 
25

 


Derivative Instruments

For the second quarter of 2014, we incurred a loss on settled derivatives of $11.2 million, compared to a $0.5 million loss for the second quarter of 2013.  Our average realized price (including all cash derivative settlements) received during the second quarter of 2014 was $78.45 per Boe compared to $79.80 per Boe in the second quarter of 2013.

We had mark-to-market derivative losses of $35.3 million in the second quarter of 2014 compared to a $17.0 million gain in the second quarter of 2013.  At June 30, 2014, all of our derivative contracts were recorded at their fair value, which was a net liability of $61.1 million, a decrease of $66.5 million from the $5.4 million net asset recorded as of June 30, 2013.

Production Expenses

Production expenses were $13.0 million in the second quarter of 2014 compared to $10.4 million in the second quarter of 2013.  We experience increases in operating expenses as we add new wells and maintain production from existing properties.  On a per unit basis, production expenses decreased from $10.49 per Boe in the second quarter of 2013 to $9.30 per Boe in the second quarter of 2014.  The lower cost on a per unit basis in 2014 is primarily due to better weather conditions in 2014 as compared to 2013, as well as a larger production base in 2014 over which the fixed cost components are spread, and was partially offset by higher workover costs and water hauling and disposal expenses.

Production Taxes

We pay production taxes based on realized crude oil and natural gas sales.  These costs were $12.2 million in the second quarter of 2014 compared to $7.6 million in the second quarter of 2013.  As a percentage of oil and natural gas sales, our production taxes were 10.1% and 9.5% in the second quarter of 2014 and 2013, respectively.  This increase in production tax rates as a percentage of oil and gas sales in the second quarter of 2014 is due to a declining portion of our production that qualifies for lower initial tax rates.  Certain of our production in Montana and North Dakota jurisdictions have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.

General and Administrative Expense

General and administrative expense was $4.0 million for the second quarter of 2014 compared to $3.9 million for the second quarter of 2013.  General and administrative expenses in 2014 as compared to 2013 included lower travel expenses of $0.2 million that were offset by higher insurance costs of $0.1 million and professional fees of $0.2 million.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $42.2 million in the second quarter of 2014 compared to $26.6 million in the second quarter of 2013.  Depletion expense, the largest component of DD&A, was $30.02 per Boe in the second quarter of 2014 compared to $26.66 per Boe in the second quarter of 2013.  The aggregate increase in depletion expense for the second quarter of 2014 compared to the second quarter of 2013 was driven by a 41% increase in production and a 13% increase in the depletion rate per Boe.  Depreciation, amortization and accretion was $0.2 million in the second quarter of 2014 compared to $0.1 million in the second quarter of 2013.  The following table summarizes DD&A expense per Boe for the second quarters of 2014 and 2013:

   
Three Months Ended
June 30,
 
   
2014
   
2013
   
Change
   
Change
 
Depletion
  $ 30.02     $ 26.66     $ 3.36       13 %
Depreciation, Amortization, and Accretion
    0.11       0.13       (0.02 )     (15 )
Total DD&A Expense
  $ 30.13     $ 26.79     $ 3.34       13 %


 
26

 


Interest Expense

Interest expense, net of capitalized interest, was $10.3 million in the second quarter of 2014 compared to $7.8 million in the second quarter of 2013.  The increase in interest expense was primarily due to increased borrowings on our Revolving Credit Facility and an additional $200 million in 8.000% senior unsecured notes due 2020 that we issued in May 2013 and were therefore outstanding for the entire period during the second quarter of 2014.

Income Tax Provision

The provision (benefit) for income taxes was a $2.8 million benefit in the second quarter of 2014 compared to $14.6 million provision in the second quarter of 2013.  The effective tax rate in the second quarter of 2014 was 38.4% compared to an effective tax rate of 36.9% in the second quarter of 2013.  The effective tax rate was different than the statutory rate of 35% primarily due to state tax rates.

Results of Operations for the six month periods ended June 30, 2014 and June 30, 2013

The following table sets forth selected operating data for the periods indicated.

   
Six Months Ended
June 30,
 
   
2014
   
2013
   
% Change
 
Net Production:
                 
Oil (Bbl)
    2,335,556       1,797,743       30  
Natural Gas and NGLs (Mcf)
    1,568,003       1,164,758       35  
Total (Boe)
    2,596,890       1,991,869       30  
                         
Net Sales:
                       
Oil Sales
  $ 205,966,449     $ 156,577,971       32  
Natural Gas and NGL Sales
    11,991,567       6,216,859       93  
Loss on Settled Derivatives
    (18,066,750 )     (870,100 )     (1,976 )
Loss on the Mark-to-Market of Derivative Instruments
    (43,167,216 )     2,099,013       (2,157 )
Other Revenue
    3,269       36,142       (91 )
Total Revenues
    156,727,319       164,059,885       (4 )
                         
Average Sales Prices:
                       
Oil (per Bbl)
  $ 88.19     $ 87.10       1  
Effect of Loss on Settled Derivatives on Average Price (per Bbl)
    (7.74 )     (0.48 )     (1,513 )
Oil Net of Settled Derivatives (per Bbl)
    80.45       86.62       (7 )
Natural Gas and NGLs (per Mcf)
    7.65       5.34       43  
Realized Price on a Boe Basis Including all Realized Derivative Settlements
    76.97       81.29       (5 )
                         
Operating Expenses:
                       
Production Expenses
  $ 24,710,750     $ 19,038,381       30  
Production Taxes
    22,004,588       15,372,460       43  
General and Administrative Expense
    7,978,509       7,904,104       1  
Depletion, Depreciation, Amortization and Accretion
    78,313,171       53,351,819       47  
                         
Costs and Expenses (per Boe):
                       
Production Expenses
  $ 9.52     $ 9.56       -  
Production Taxes
    8.47       7.72       10  
General and Administrative Expense
    3.07       3.97       (23 )
Depletion, Depreciation, Amortization and Accretion
    30.16       26.78       13  
                         
Net Producing Wells at Period End
    165.2       121.5       36  


 
27

 


Oil and Natural Gas Sales

In the first half of 2014, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 34% as compared to the first half of 2013, driven by a 30% increase in production and partially aided by a 4% increase in realized prices, excluding the effect of settled derivatives.  The higher average realized price in the first half of 2014 as compared to the same period in 2013 was driven by a higher oil price differential, partially offset by higher average NYMEX oil prices.  Oil price differential during the first half of 2014 was $12.65 per barrel, as compared to $4.47 per barrel in the first half of 2013.

As discussed above, we add production through drilling success as we place new wells into production and through additions from acquisitions, partially offset by the natural decline of our oil and natural gas sales from existing wells.  During the first half of 2014, our production volumes increased 30% as compared to the first half of 2013.  Production primarily increased due to our continued addition of net producing wells.

Derivative Instruments

For the first half of 2014, we incurred a loss on settled derivatives of $18.1 million, compared to a $0.9 million loss for the first half of 2013.  Our average realized price (including all cash derivative settlements) received during the first half of 2014 was $76.97 per Boe compared to $81.29 per Boe in the first half of 2013.

We had a mark-to-market derivative loss of $43.2 million in the first half of 2014 compared to a $2.1 million gain in the first half of 2013.  At June 30, 2014, all of our derivative contracts were recorded at their fair value, which was a net liability of $61.1 million, a decrease of $66.5 million from the $5.4 million net asset recorded as of June 30, 2013.

Production Expenses

Production expenses were $24.7 million in the first half of 2014 compared to $19.0 million in the first half of 2013.  We experience increases in operating expenses as we add new wells and maintain production from existing properties.  On a per unit basis, production expenses decreased from $9.56 per Boe in the first half of 2013 to $9.52 in the first half of 2014.

Production Taxes

We pay production taxes based on realized crude oil and natural gas sales.  These costs were $22.0 million in the first half of 2014 compared to $15.4 million in the first half of 2013.  As a percentage of oil and natural gas sales, our production taxes were 10.1% and 9.4% in the first half of 2014 and 2013, respectively.  This increase in production tax rates as a percentage of oil and gas sales in the first quarter of 2014 is due to a declining portion of our production that qualifies for lower initial tax rates.  Certain of our production in Montana and North Dakota jurisdictions have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.

General and Administrative Expense

General and administrative expense was $8.0 million for the first half of 2014 compared to $7.9 million for the first half of 2013.  General and administrative expenses in the first half of 2014 as compared to 2013 included lower compensation related expenses of $0.3 million and travel expenses of $0.4 million that were offset by higher insurance costs of $0.4 million and professional fees of $0.4 million.


 
28

 


Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $78.3 million in the first half of 2014 compared to $53.4 million in the first half of 2013.  Depletion expense, the largest component of DD&A, was $30.02 per Boe in the first half of 2014 compared to $26.66 per Boe in the first half of 2013.  The aggregate increase in depletion expense for the first half of 2014 compared to 2013 was driven by a 30% increase in production and a 13% increase in the depletion rate per Boe.  Depreciation, amortization and accretion was $0.4 million in the first half of 2014 compared to $0.2 million in the first half of 2013.  The following table summarizes DD&A expense per Boe for the first half of 2014 and 2013:

   
Six Months Ended
June 30,
 
   
2014
   
2013
   
Change
   
Change
 
Depletion
  $ 30.02     $ 26.66     $ 3.36       13 %
Depreciation, Amortization, and Accretion
    0.14       0.12       0.02       17  
Total DD&A Expense
  $ 30.16     $ 26.78     $ 3.38       13 %

Interest Expense

Interest expense, net of capitalized interest, was $20.2 million for the first half of 2014 compared to $13.9 million in the first half of 2013.  The increase in interest expense was primarily due to increased borrowings on our Revolving Credit Facility and an additional $200 million in 8.000% senior unsecured notes due 2020 that we issued in May 2013 and were therefore outstanding for the entire period during the first half of 2014, but not the first half of 2013.

Income Tax Provision

The provision for income taxes was $1.4 million in the first half of 2014 compared to $20.2 million in the first half of 2013.  The effective tax rate in the first half of 2014 was 38.3% compared to an effective tax rate of 37.3% in the first half of 2013.  The effective tax rate was different than the statutory rate of 35% primarily due to state tax rates.


Non-GAAP Financial Measures

We define Adjusted Net Income as net income excluding (gain) loss on the mark-to-market of derivative instruments, net of tax.  Our Adjusted Net Income for the second quarter of 2014 was $17.4 million (representing approximately $0.29 per diluted share), compared to $14.6 million (representing approximately $0.23 per diluted share) for the second quarter of 2013.  The increase in non-GAAP Adjusted Net Income is primarily due to our continued addition of crude oil and natural gas production from new wells in 2014 compared to 2013, which was partially offset by higher interest, operating and depletion expenses.  Our Adjusted Net Income for the first half of 2014 was $28.8 million (representing approximately $0.47 per diluted share), compared to $32.7 million (representing approximately $0.52 per diluted share) for the first half of 2013.  The decrease in non-GAAP Adjusted Net Income is primarily due to lower realized commodity prices as well as higher interest, operating and depletion expenses, which were partially offset by our continued addition of crude oil and natural gas production from new wells in 2014 compared to 2013.

We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments and (v) non-cash share based compensation expense.  Adjusted EBITDA for the second quarter of 2014 was $81.4 million, compared to Adjusted EBITDA of $58.2 million for the second quarter of 2013.  Adjusted EBITDA for the first half of 2014 was $146.5 million, compared to Adjusted EBITDA of $121.7 million for the first half of 2013.  The increase in Adjusted EBITDA is primarily due to our continued addition of crude oil and natural gas production from new wells, which was partially offset by lower realized commodity prices in 2014 compared to 2013.


 
29

 


We believe the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of our current financial performance.  Specifically, we believe the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that our management believes are not indicative of our core operating results.  In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes.  We consider these non-GAAP measures to be useful in evaluating our core operating results as they more closely reflect our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities.  Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.

These measures should be considered in addition to results prepared in accordance with GAAP.  In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles.  We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures.  A reconciliation of these measures to GAAP is included below:

Reconciliation of Adjusted Net Income

 
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
Net Income (Loss)
  $ (4,412,450 )   $ 25,011,673     $ 2,177,314     $ 33,963,192  
Add:
                               
Loss (Gain) on the Mark-to-Market of Derivative Instruments, Net of Tax
    21,749,440       (10,410,668 )     26,591,005       (1,241,013 )
Adjusted Net Income
  $ 17,336,990     $ 14,601,005     $ 28,768,319     $ 32,722,179  
                                 
Weighted Average Shares Outstanding – Basic
    60,504,781       62,973,916       60,852,322       62,915,941  
Weighted Average Shares Outstanding – Diluted
    60,676,947       63,358,152       61,059,485       63,337,342  
                                 
Net Income Per Common Share - Basic
  $ (0.07 )   $ 0.40     $ 0.04     $ 0.54  
Add:
                               
Change due to Loss (Gain) on the Mark-to-Market of Derivative Instruments, Net of Tax
    0.36       (0.17 )     0.43       (0.02 )
Adjusted Net Income Per Common Share – Basic
  $ 0.29     $ 0.23     $ 0.47     $ 0.52  
                                 
Net Income Per Common Share – Diluted
  $ (0.07 )   $ 0.39     $ 0.04     $ 0.54  
Add:
                               
Change due to Loss (Gain) on the Mark-to-Market of Derivative Instruments, Net of Tax
    0.36       (0.16 )     0.43       (0.02 )
Adjusted Net Income Per Common Share – Diluted
  $ 0.29     $ 0.23     $ 0.47     $ 0.52  


 
30

 


Reconciliation of Adjusted EBITDA

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2014
   
2013
   
2014
   
2013
 
Net Income (Loss)
  $ (4,412,450 )   $