Form 8-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): September 19, 2018

 

 

NORTHERN OIL AND GAS, INC.

(Exact name of Registrant as specified in its charter)

 

 

 

Delaware   001-33999   95-3848122

(State or other jurisdiction

of incorporation)

 

(Commission

File Number)

 

(IRS Employer

Identification No.)

 

601 Carlson Parkway, Suite 990

Minnetonka, Minnesota

  55305
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code (952) 476-9800

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17CFR 240.14a-12)

 

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17CFR §240.12b-2).

Emerging growth company  ☐

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

 

 

 


Item 7.01.

Regulation FD Disclosure.

Operational Update

In connection with its previously announced private offering of 8.50% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Notes”), Northern Oil and Gas, Inc. (the “Company”) provided additional information to investors regarding its reserves, swap positions and certain pro forma financial statements as described below (including, where indicated, (i) assets acquired from affiliates of Pivotal Petroleum Partners LP and Pivotal Petroleum Partners II LP (the “Pivotal Acquisition”), namely Pivotal Williston Basin, LP and Pivotal Williston Basin II, LP (together, the “Pivotal Entities”) and (ii) assets subject to our pending acquisition from WR Operating LLC (“W Energy”) that is expected to close no later than October 11, 2018).

******

The following table provides a summary of certain information regarding our assets:

 

     Operational Data
(as of June 30, 2018)
     Reserves
(as of June 30, 2018)
 
     Net
Acres
     Gross
Wells
     Net
Wells
     Proved
Reserves
(MMBoe)

(2)
     % Oil     % Proved
Developed
    PV-10
SEC
Pricing (in
thousands)

(1)
     PV-10 Strip
Pricing (in
thousands)

(2)
     PV-10 of
PDP
Reserves (in
thousands)

(2)
 

Northern Historical

     142,248        3,510        248.3        87.4        81     67     1,175,633        1,187,475        767,342  

Pivotal

     444        334        20.8        8.3        83     87     144,344        149,236        108,475  

W Energy

     10,633        910        27.2        19.5        79     60     290,551        292,907        150,082  
  

 

 

       

 

 

    

 

 

        

 

 

    

 

 

    

 

 

 

Total

     153,325        4,408        296.3        115.2        81     67     1,610,528        1,629,618        1,025,899  
  

 

 

       

 

 

    

 

 

        

 

 

    

 

 

    

 

 

 

 

(1)

PV-10 is a non-GAAP financial measure. The prices used to calculate this measure were $57.67 per barrel of oil (WTI-Cushing spot price) and $2.92 per MMBtu of natural gas (Henry Hub price), which prices were then further adjusted for transportation, quality and basis differentials.

(2)

The prices used to calculate this measure were based on NYMEX strip prices as of June 29, 2018.

(3)

The total gross wells reflects our total gross well count, pro forma for the Salt Creek Acquisition, Pivotal Acquisition and W Energy Acquisition, due to our holding a prior interest in 346 gross wells that were acquired.

******


Our acreage position, as of June 30, 2018 is presented in the following table:

 

     Net Acres  

Location

   Developed      Undeveloped      Total      %
Developed
 

North Dakota:

           

Mountrail County

     26,506        923        27,429        97

Dunn County

     16,370        668        17,038        96

McKenzie County

     27,182        1,885        29,067        94

Williams County

     17,844        1,656        19,500        92

Divide County

     15,532        1,157        16,689        93

Other

     14,039        3,712        17,751        79
  

 

 

    

 

 

    

 

 

    

North Dakota

     117,473        10,001        127,474        92

Montana

     11,238        3,536        14,774        76
  

 

 

    

 

 

    

 

 

    

Northern Historical

     128,711        13,537        142,248        90
  

 

 

    

 

 

    

 

 

    

Pivotal

     444        —          444        100

W Energy

     10,592        41        10,633        100
  

 

 

    

 

 

    

 

 

    

Total(1)

     139,747        13,578        153,325        91
  

 

 

    

 

 

    

 

 

    

 

(1)

Pro forma for the net acreage attributed to the Pivotal and W Energy acquisitions.

******

The following table summarizes the open oil derivative contracts that we have entered into that settle after June 30, 2018, by year:

 

Open Contracts

 
Year    Swap Volume (Bbls)      Weighted Average Swap
Price ($ per Bbl)
 

2018

     2,858,760        60.53  

2019

     4,130,580        57.94  

2020

     2,013,080        53.82  

2021 and beyond

     631,600        55.67  

******

The unaudited pro forma financial statements of the Company for the year ended December 31, 2017 and six months ended June 30, 2018 and 2017, giving effect to the Pivotal Acquisitions and the acquisition of certain oil and gas properties and interests from W Energy, are furnished as Exhibit 99.1 and incorporated by reference herein.

The consolidated financial statements of W Energy for the year ended December 31, 2017 and the period from May 17, 2016 (inception) through December 31, 2016 are furnished as Exhibit 99.2 and incorporated by reference herein.

The consolidated financial statements of W Energy for the three and six month period ended June 30, 2018 and 2017 and the year ended December 31, 2017 are furnished as Exhibit 99.3 and incorporated by reference herein.

The statement of revenues and direct operating expenses of the Pivotal Entities for the year ended December 31, 2017 and six months ended June 30, 2018 and 2017 are furnished as Exhibit 99.4 and incorporated by reference herein.

The information in this Item 7.01, including Exhibits 99.1, 99.2, 99.3 and 99.4, is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of Section 18, and shall not be incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except as set forth by specific reference in such filing.


Item 9.01.

Financial Statements and Exhibits.

(d) Exhibits

 

Exhibit

    No.    

  

Description

99.1    Unaudited Pro Forma Financial Statements for the Year Ended December 31, 2017 and Six Months Ended June 30, 2018 and 2017.
99.2    Consolidated Financial Statements of W Energy for the Year Ended December 31, 2017 and the period from May 17, 2016 through December 31, 2016
99.3    Consolidated Financial Statements of W Energy for the Three and Six Month Periods Ended June 30, 2018 and 2017 and the Year Ended December 31, 2017
99.4    Statement of Revenue and Direct Operating Expenses of the Pivotal Entities for the Year Ended December 31, 2017 and Six Months Ended June 30, 2018 and 2017


SIGNATURES

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

 

Date: September 19, 2018     NORTHERN OIL AND GAS, INC.
    By  

/s/ Erik J. Romslo

     

Erik J. Romslo

Executive Vice President, General Counsel and Secretary

EX-99.1

Exhibit 99.1

UNAUDITED PRO FORMA FINANCIAL STATEMENTS AND OTHER DATA

The following unaudited pro forma financial statements present our unaudited pro forma balance sheet as of June 30, 2018, unaudited pro forma statement of income for the year ended December 31, 2017, and unaudited pro forma statement of income for the six months ended June 30, 2017 and June 30, 2018. The unaudited pro forma statements of income have been developed by applying pro forma adjustments to our historical statements of income to give effect to the Pivotal and W Energy Acquisitions, as if these transactions had occurred on January 1, 2017.

The unaudited pro forma balance sheet has been developed by applying pro forma adjustments to our historical balance sheet to give effect to the Pivotal and W Energy Acquisitions, as if these transactions had occurred on June 30, 2018.

The unaudited pro forma financial statements are for illustrative and informational purposes only and are not intended to represent or be indicative of what our results of operations would have been had the above transactions occurred as of or on the dates indicated. The unaudited pro forma financial statements also should not be considered representative of our future results of operations and do not give effect to the Refinancing.

The pro forma adjustments related to the Pivotal and W Energy Acquisitions are based on preliminary estimates, accounting judgments and currently available information and assumptions that management believes are reasonable and are subject to change. Accordingly, these pro forma adjustments are preliminary and have been made solely for the purpose of providing these unaudited pro forma financial statements. Differences between these preliminary estimates and the final acquisition accounting may occur and these differences could be material. The differences, if any, could have a material impact on the accompanying unaudited pro forma financial statements and our future results of operations.


NORTHERN OIL AND GAS, INC.

UNAUDITED PRO FORMA BALANCE SHEET

(in thousands)

(unaudited)

 

    As of June 30, 2018  
    Historical
Northern
Oil and
Gas, Inc.
    Historical
W Energy
    Pro Forma
W Energy
Acquisition
Adjustments
        Pro Forma
Pivotal
Acquisition
Adjustments
        Pro Forma
Combined
 
    (in thousands)  

Assets

             

Current Assets:

             

Cash and Cash Equivalents

  $ 200,924     $ 1,590     $ (101,590   (a), (c)   $ (60,600   (b)   $ 40,324  

Accounts Receivable, Net

    68,273       10,042       (10,042   (c)             68,273  

Advances to Operators

    416                             416  

Prepaid Expenses and Other Current Assets

    5,585       391       (391   (c)             5,585  

Due from Affiliates

          104       (104   (c)              

Income Tax Receivables

    785                             785  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Current Assets

    275,983       12,127       (112,127       (60,600       115,383  

Oil and Natural Gas Properties, Full Cost Method of Accounting:

             

Proved Properties

    2,754,033       155,970       137,949     (a), (d)     149,193     (b)     3,197,145  

Unproved Properties

    1,830                             1,830  

Other Property and Equipment

    963       4       (4   (c)             963  

Less Accumulated Depreciation, Depletion, Amortization and Impairment

    (2,155,813     (20,946     20,946     (d)             (2,155,813
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Oil and Natural Gas Properties, Net

    601,013       135,028       158,891         149,193         1,044,125  

Other Assets:

             

Deferred Income Taxes

    785                             785  

Other Noncurrent Assets, Net

    5,302                             5,302  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Assets

  $ 883,083     $ 147,155     $ 46,764       $ 88,593       $ 1,165,595  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Liabilities and Stockholders’ Equity (Deficit)/Members’ Capital

             

Current Liabilities:

             

Accounts Payable

  $ 92,176     $ 10,260     $ (10,260   (c)   $       $ 92,176  

Accrued Expenses

    5,917                             5,917  

Accrued Interest

    4,860                             4,860  

Derivative Instruments

    43,645                             43,645  

Debt Exchange Derivative

    10,923                             10,923  

Asset Retirement Obligations—Current Portion

    483                             483  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Current Liabilities

    158,004       10,260       (10,260               158,004  

Long-Term Liabilities:

             

Long-term debt, net

    834,768       9,000       (9,000   (c)             834,768  

Derivative instruments

    28,611                             28,611  

Asset retirement obligations, net of current portion

    9,400       318       (318   (c)             9,400  

Other noncurrent liabilities

    120                             120  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Liabilities

    1,030,903       19,578       (19,578               1,030,903  

Stockholders’ Equity (Deficit)/Members’ Capital:

             

Preferred stock, par value $.001; 5,000,000 authorized, no shares outstanding

                                 

“Common stock, par value $.001; 450,000,000 authorized, 375,725,746 shares outstanding”

    294             56     (a)     26     (b)     376  

Additional paid-in capital

    886,041             193,863     (a)     88,567     (b)     1,168,471  

Members’ Capital

          127,577       (127,577   (c)              

Accumulated deficit

    (1,034,155                           (1,034,155
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Stockholders’ Equity/Members’ Capital

    (147,820     127,577       66,342         88,593         134,692  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

Total Liability and Stockholders’ Equity (Deficit)/Members’ Capital

  $ 883,083     $ 147,155     $ 46,764       $ 88,593       $ 1,165,595  
 

 

 

   

 

 

   

 

 

     

 

 

     

 

 

 

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


NORTHERN OIL AND GAS, INC.

UNAUDITED PRO FORMA INCOME STATEMENT

(in thousands)

(unaudited)

 

    For the Year Ended December 31, 2017  
    Historical
Northern
Oil and Gas
    Historical
Pivotal(g)
    Pivotal
Acquisition
Adjustments
        Historical
W Energy
    W Energy
Acquisition
Adjustment
        Northern
Oil and Gas
Combined
Pro Forma
 
    (in thousands)  

Revenues

               

Oil and Gas Sales

  $ 223,963     $ 50,047     $       $ 35,496     $       $ 309,506  

Gain (Loss) on Derivative Instruments, Net

    (14,667                                 (14,667

Other Revenue

    23                                   23  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Revenues

    209,319       50,047               35,496               294,862  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Operating Expenses

               

Production Expenses

    49,733       12,206               9,252               71,191  

Production Taxes

    20,604       4,309               2,894               27,807  

General and Administrative Expense

    18,988                     2,577               21,565  

Depletion, Depreciation, Amortization and Accretion

    59,500             21,142     (e)     8,237       12,629     (f)     101,508  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Expenses

    148,825       16,515       21,142         22,960       12,629         222,071  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) from Operations

    60,494       (229,305     (21,142       12,536       (12,629       72,791  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Other Income and Expense

               

Interest Expense, Net of Capitalization

    (70,286                                 (70,286

Write-off of Debt Issuance Costs

    (95                                 (95

Loss on the Extinguishment of Debt

    (993                                 (993

Other Income (Expense)

    116                     46               162  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Other Income (Expense)

    (71,258                   46               (71,212
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) Before Income Taxes

    (10,764     33,532       (21,142       12,582       (12,629       1,579  

Income Tax Benefit

    (1,570                                 (1,570
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Net (Loss) Income

  $ (9,194   $ 33,532     $ (21,142     $ 12,582     $ (12,629     $ 3,149  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

 

    For the Six Months Ended June 30, 2018  
    Historical
Northern
Oil and Gas
    Historical
Pivotal(g)
    Pivotal
Acquisition
Adjustments
          Historical
W Energy
    W Energy
Acquisition
Adjustment
          Northern
Oil and Gas
Combined
Pro Forma
 
    (in thousands)  

Revenues

               

Oil and Gas Sales

  $ 195,928     $ 30,217     $       $ 41,416     $       $ 267,561  

Gain (Loss) on Derivative Instruments, Net

    (62,474                                 (62,474

Other Revenue

    5                                   5  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Revenues

    133,459       30,217               41,416               205,092  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Operating Expenses

               

Production Expenses

    27,037       4,964               9,089               41,090  

Production Taxes

    18,054       2,757               2,430               23,241  

General and Administrative Expense

    4,918                     1,158               6,076  

Depletion, Depreciation, Amortization and Accretion

    41,227             10,163       (e     9,680       6,035       (f     67,105  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Expenses

    91,236       7,721       10,163         22,357       6,035         137,512  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) from Operations

    42,223       22,496       (10,163       19,059       (6,035       67,580  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Other Income and Expense

               

Interest Expense, Net of Capitalization

    (45,510                   (76             (45,586

Write-off of Debt Issuance Costs

                                       

Loss on the Extinguishment of Debt

    (90,833                                 (90,833

Other Income (Expense)

    538                                   538  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Other Income (Expense)

    (135,805                   (76             (135,881
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) Before Income Taxes

    (93,582     22,496       (10,163       18,983       (6,035       (68,301

Income Tax Benefit

                                       
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Net (Loss) Income

  $ (93,582   $ 22,496     $ (10,163     $ 18,983     $ (6,035     $ (68,301
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

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


NORTHERN OIL AND GAS, INC.

UNAUDITED PRO FORMA INCOME STATEMENT

(in thousands)

(unaudited)

 

    For the Six Months Ended June 30, 2017  
    Historical
Northern
Oil and Gas
    Historical
Pivotal(g)
    Pivotal
Acquisition
Adjustments
          Historical W
Energy
    W Energy
Acquisition
Adjustments
          Northern
Oil and Gas
Combined
Pro Forma
 
    (in thousands)  

Revenues

               

Oil and Gas Sales

  $ 97,229     $ 27,730     $       $ 14,336     $       $ 139,295  

Gain (Loss) on Derivative Instruments, Net

    33,474                                   33,474  

Other Revenue

    16                                   16  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Revenues

    130,719       27,730               14,336               172,785  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Operating Expenses

               

Production Expenses

    23,812       7,790               3,665               35,267  

Production Taxes

    8,901       2,520               1,180               12,601  

General and Administrative Expenses

    7,926                     1,170               9,096  

Depletion, Depreciation, Amortization, and Accretion

    26,511             11,875       (e     2,046       7,482       (f     47,914  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Expenses

    67,150       10,310       11,875         8,061       7,482         104,878  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) from Operations

    63,569       17,420       (11,875       6,275       (7,482       67,907  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Other Income and Expense

               

Interest Expense, Net of Capitalization

    (32,732                                 (32,732

Write-off of Debt Issuance Costs

    (95                                 (95

Loss on the Extinguishment of Debt

                                      (993

Other Income (Expense)

                                       
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Total Other Income (Expense)

    (32,827                                 (32,827
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Income (Loss) Before Taxes

    30,742       17,420       (11,875       6,275       (7,482       35,080  

Income Tax Benefit

                                       
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

Net Income (Loss)

  $ 30,742     $ 17,420     $ (11,875     $ 6,275     $ (7,482     $ 35,080  
 

 

 

   

 

 

   

 

 

     

 

 

   

 

 

     

 

 

 

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


NOTE 1. BASIS OF PRO FORMA PRESENTATION

These financial statements present our unaudited pro forma balance sheet as of June 30, 2018, unaudited pro forma statement of operations for the year ended December 31, 2017 and unaudited pro forma statement of operations for the six months ended June 30, 2018 and 2017. These unaudited statements have been developed by applying pro forma adjustments to our historical financial statements to give effect to the Pivotal and W Energy Acquisitions.

The unaudited pro forma financial statements were prepared in accordance with Regulation S-X Article 11 of the Securities and Exchange Commission.

The pro forma adjustments related to the purchase price allocation of the Pivotal and W Energy Acquisitions are preliminary and are subject to revisions as additional information becomes available. Revisions to the preliminary purchase price allocation may have a significant impact on the pro forma amounts of depreciation, depletion, amortization and accretion expense and impairment for full cost ceiling limitation. The pro forma adjustments related to the Pivotal and W Energy Acquisitions reflect the fair values of the assets as of September 17, 2018. The pro forma adjustments related to these acquisitions do not necessarily reflect the fair values that would have been recorded if the applicable acquisition had occurred on January 1, 2017 or June 30, 2018.

The unaudited pro forma financial statements should be read together with our historical financial statements and the related notes as of and for the year ended December 31, 2017 and the six months ended June 30, 2018 and 2017, the historical statements of revenues and direct operating expenses for the Pivotal Acquisition for the year ended December 31, 2017, and the six months ended June 30, 2018 and 2017, and the historical financial statements and related notes for the W Energy Acquisition as of and for the years ended December 31, 2017 and 2016, and the six months ended June 30, 2018 and 2017.

The pro forma financial information presented reflects events directly attributable to the Pivotal and W Energy Acquisitions and certain assumptions that we believe are reasonable. The pro forma financial information is not necessarily indicative of financial results that would have been attained had the Pivotal and W Energy Acquisitions occurred on the date indicated or which could be achieved in the future. The pro forma adjustments are based on currently available information and certain estimates and assumptions. However, our management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transaction as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

NOTE 2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The accompanying unaudited pro forma combined financial statements reflect the following pro forma adjustments:

 

  (a)

Represents the preliminary purchase price allocation for the W Energy Acquisition of $100.0 million in cash and 56,371,899 shares of our common stock valued as of September 17, 2018 at $3.44 (the closing price) per share for total consideration of $293.9 million. The shares will be subject to a limited lock-up over a 13-month post-closing period, which includes a mechanism for potential additional consideration if our common stock trades below certain price targets. The price targets range from $3.49 to $3.79 per share.

 

  (b)

Represents the preliminary purchase price allocation for the Pivotal Acquisition of $60.6 million in cash and 25,753,578 shares of our common stock valued as of September 17, 2018 at $3.44 (the closing price) per share for total consideration of $149.2 million. The shares will be subject to a limited lock-up over a 13-month post-closing period, which includes a mechanism for potential additional consideration if our common stock trades below certain price targets. The price targets range from $3.10 to $3.40 per share.


  (c)

Represents the elimination of historical assets, liabilities, and members’ capital related to the W Energy Acquisition that we are not acquiring or assuming.

 

  (d)

Represents the elimination of the historical W Energy Acquisition proved oil and natural gas properties of $156.0 million and related accumulated depreciation, depletion, amortization, and accretion of $20.9 million, which was offset by the preliminary purchase price allocation for the W Energy Acquisition of $293.9 million, which was recorded as proved oil and natural gas properties.

 

  (e)

Represents the increase in depreciation, depletion, amortization, and accretion expense computed on a unit of production basis following the preliminary purchase price allocation to proved oil and natural gas properties, as if the Pivotal Acquisition was consummated on January 1, 2017.

 

  (f)

Represents the increase in depreciation, depletion, amortization, and accretion expense computed on a unit of production basis following the preliminary purchase price allocation to proved oil and natural gas properties, as if the W Energy Acquisition was consummated on January 1, 2017.

 

  (g)

Represents the historical revenues and direct operating expenses of the Pivotal Acquisition.

NOTE 3. SUPPLEMENTAL PRO FORMA COMBINED OIL AND NATURAL GAS RESERVE AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

The following unaudited supplemental pro forma oil and natural gas reserve tables present how the combined oil and natural gas reserves and standardized measure information of the Company, the Pivotal Acquisition, and the W Energy Acquisition may have appeared had the Pivotal and W Energy Acquisitions occurred on January 1, 2017. The supplemental pro forma combined oil and natural gas reserves and standardized measure information are for illustrative purposes only.

All of the reserves are located in the United States. Reserve estimates are based on the following:

(a) For the Company’s Historical Results: as reported in our Annual Report on Form 10-K for the year ended December 31, 2017, based upon a reserve report prepared by the independent petroleum engineers as of December 31, 2017;

(b) For the Pivotal Acquisition Historical Results: as reported in its audited statement of revenues and direct operating expenses and related footnotes for the year ended December 31, 2017, based upon a reserve report prepared by the independent petroleum engineers as of December 31, 2017;

(c) For the W Energy Acquisition Historical Results: as reported in its audited financial statements and related footnotes for the years ended December 31, 2017 and 2016, based upon a reserve report prepared by their internal petroleum engineers as of December 31, 2017;

Numerous uncertainties are inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents an estimate only and should not be construed as the current market value of the estimated oil and natural gas reserves reported below.

The pro forma estimates of proved reserves presented below include only those quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from


known reservoirs under existing economic, operating and regulatory practices. Proved developed reserves represent only those reserves estimated to be recovered through existing wells. Proved undeveloped reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operation is required.

The following tables provide a summary of the changes in estimated proved reserves for the year ended

December 31, 2017, as well as pro forma proved developed and proved undeveloped reserves as of the beginning and end of the year, giving effect to the Pivotal Acquisition and W Energy Acquisitions as if they had occurred on January 1, 2017. The pro forma standardized measure does not include future income taxes attributable to the Pivotal and W Energy Acquisitions as both entities are considered pass-through entities for tax purposes.

Estimated Pro Forma Combined Quantities of Proved Reserves

(in thousands)

 

     Historical Northern Oil and Gas  
     Natural Gas     Oil        
     (MMcf)     (MBbl)     MBOE  

Proved Developed and Undeveloped Reserves at December 31, 2016

     46,832       46,275       54,081  
  

 

 

   

 

 

   

 

 

 

Acquisitions of reserves

                  

Revisions of Previous Estimates

     8,839       890       2,363  

Extensions, Discoveries and Other Additions

     27,637       20,184       24,790  

Production

     (5,188     (4,537     (5,402
  

 

 

   

 

 

   

 

 

 

Proved Developed and Undeveloped Reserves at December 31, 2017

     78,120       62,812       75,832  
  

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

      

December 31, 2016

     32,808       32,245       37,713  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     46,518       38,592       46,345  
  

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

      

December 31, 2016

     14,024       14,030       16,368  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     31,602       24,220       29,487  
  

 

 

   

 

 

   

 

 

 

 

     Historical Pivotal Acquisition  
     Natural Gas     Oil        
     (MMcf)     (MBbl)     MBOE  

Proved Developed and Undeveloped Reserves at December 31, 2016

     5,866       5,702       6,680  
  

 

 

   

 

 

   

 

 

 

Acquisitions of reserves

     363       104       165  

Revisions of Previous Estimates

     4,518       754       1,507  

Extensions, Discoveries and Other Additions

                  

Production

     (1,706     (995     (1,279
  

 

 

   

 

 

   

 

 

 

Proved Developed and Undeveloped Reserves at December 31, 2017

     9,041       5,565       7,072  
  

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

      

December 31, 2016

     5,866       5,702       6,680  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     9,041       5,565       7,072  
  

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

      

December 31, 2016

                  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

                  
  

 

 

   

 

 

   

 

 

 


     Historical W Energy Acquisition  
     Natural Gas     Oil        
     (MMcf)     (MBbl)     MBOE  

Proved Developed and Undeveloped Reserves at December 31, 2016

     4,272       1,330       2,042  
  

 

 

   

 

 

   

 

 

 

Acquisitions of reserves

     16,632       10,023       12,795  

Revisions of Previous Estimates

     54       14       23  

Extensions, Discoveries and Other Additions

     3,228       2,153       2,691  

Production

     (1,650     (582     (857
  

 

 

   

 

 

   

 

 

 

Proved Developed and Undeveloped Reserves at December 31, 2017

     22,536       12,938       16,694  
  

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

      

December 31, 2016

     4,272       1,330       2,042  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     19,308       10,785       14,003  
  

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

      

December 31, 2016

                  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     3,228       2,153       2,691  
  

 

 

   

 

 

   

 

 

 

 

     Northern Oil and Gas Combined
Pro Forma
 
     Natural Gas     Oil        
     (MMcf)     (MBbl)     MBOE  

Proved Developed and Undeveloped Reserves at December 31, 2016

     56,970       53,307       62,803  
  

 

 

   

 

 

   

 

 

 

Acquisitions of reserves

     16,995       10,127       12,960  

Revisions of Previous Estimates

     13,411       1,658       3,893  

Extensions, Discoveries and Other Additions

     30,865       22,337       27,481  

Production

     (8,544     (6,114     (7,538
  

 

 

   

 

 

   

 

 

 

Proved Developed and Undeveloped Reserves at December 31, 2017

     109,697       81,315       99,598  
  

 

 

   

 

 

   

 

 

 

Proved Developed Reserves:

      

December 31, 2016

     42,946       39,277       46,435  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     74,867       54,942       67,420  
  

 

 

   

 

 

   

 

 

 

Proved Undeveloped Reserves:

      

December 31, 2016

     14,024       14,030       16,368  
  

 

 

   

 

 

   

 

 

 

December 31, 2017

     34,830       26,373       32,178  
  

 

 

   

 

 

   

 

 

 


Pro Forma Combined Standardized Measure of Discounted Future Net Cash Flows

(in thousands)

 

     As of December 31, 2017  
     Historical
Northern
Oil and Gas
    Historical
Pivotal
Acquisition
    Historical
W Energy
Acquisition
    Northern
Oil and Gas
combined
Pro forma
 

Future Cash Inflows

   $ 3,143,604     $ 297,879     $ 648,643     $ 4,090,126  

Future Production Costs

     (1,265,525     (141,448     (233,791     (1,640,764

Future Development Costs

     (409,360     (14,675     (57,217     (481,252

Future Income Tax Expense

     (27,476                 (27,476
  

 

 

   

 

 

   

 

 

   

 

 

 

Future Net Cash Flows

     1,441,243       141,756       357,635       1,940,634  
  

 

 

   

 

 

   

 

 

   

 

 

 

10% Annual Discount for Estimated Timing of Cash Flows

     (687,257     (49,542     (183,833     (920,632
  

 

 

   

 

 

   

 

 

   

 

 

 

Standardized Measure of Discounted Future Net Cash Flows

   $ 753,986     $ 92,214     $ 173,802     $ 1,020,002  
  

 

 

   

 

 

   

 

 

   

 

 

 

Pro Forma Combined Changes in the Standardized Measure of Discounted Future Net Cash Flows

(in thousands)

 

     As of December 31, 2017  
     Historical
Northern
Oil and Gas
    Historical
Pivotal
Acquisition
    Historical
W Energy
Acquisition
    Northern
Oil and Gas
combined
Pro forma
 

Standard measure, beginning of year

   $ 379,026     $ 62,616     $ 20,929     $ 462,571  

Sales of oil and natural gas produced, net of production costs

     (153,626     (33,533     (23,350     (210,509

Extensions and discoveries

     217,146             28,019       245,165  

Previously estimated development costs incurred

     46,834       2,590             49,424  

Net change of prices and production costs

     216,217       27,236       2,594       246,047  

Change in future development costs

     (34,754     3,174             (31,580

Revisions of previous quantity estimates

     28,915       19,789       231       48,935  

Accretion of discount

     37,942       6,262       14,631       58,835  

Change in income taxes

     (3,617                 (3,617

Acquisition of reserves

           2,329       133,213       135,542  

Changes in timing and other

     19,903       1,751       (2,465     19,189  
  

 

 

   

 

 

   

 

 

   

 

 

 

Standard measure, end of year

   $ 753,986     $ 92,214     $ 173,802     $ 1,020,002  
  

 

 

   

 

 

   

 

 

   

 

 

 
EX-99.2

Exhibit 99.2

REPORT OF INDEPENDENT AUDITORS

To the Members of

W Energy Partners LLC

We have audited the accompanying consolidated financial statements of W Energy Partners LLC (the “Company”), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of operations, members’ capital, and cash flows for the year ended December 31, 2017, and period from May 17, 2016 (Inception) through December 31, 2016, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”); this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of die financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of W Energy Partners LLC as of December 31, 2017 and 2016, and the results of their operations and their cash flows for the year ended December 31, 2017, and period from May 17, 2016 (Inception) through December 31, 2016, in conformity with GAAP.

/s/ Whitley Penn LLP

Dallas, Texas

September 12, 2018


W ENERGY PARTNERS LLC

CONSOLIDATED BALANCE SHEETS

 

     December 31,  
     2017     2016  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 4,847,878     $ 2,209,342  

Accounts receivable

     12,170,774       4,485,085  

Due from affiliates

     238,150       370,179  

Prepaid expenses and other current assets

     631,937       650,745  
  

 

 

   

 

 

 

Total current assets

     17,888,739       7,715,351  

Oil and natural gas properties (full-cost accounting):

    

Proved oil and natural gas properties

     114,043,497       29,503,798  

Accumulated depletion, depreciation and amortization

     (11,274,573     (3,048,936
  

 

 

   

 

 

 

Total oil and natural gas properties, net

     102,768,924       26,454,862  

Non oil and gas property and equipment, net

     4,771       2,216  
  

 

 

   

 

 

 

Total assets

   $ 120,662,434     $ 34,172,429  
  

 

 

   

 

 

 

Liabilities and Members’ Capital

    

Current liabilities:

    

Accounts payable

   $ 10,841,124     $ 2,702,844  

Accrued liabilities

     1,069,145       896,584  
  

 

 

   

 

 

 

Total current liabilities

     11,910,269       3,599,428  

Asset retirement obligations, long-term

     297,106       55,064  
  

 

 

   

 

 

 

Total liabilities

     12,207,375       3,654,492  

Commitments and contingencies

    

Members’ capital

     108,455,059       30,517,937  
  

 

 

   

 

 

 

Total liabilities and members’ capital

   $ 120,662,434     $ 34,172,429  
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.


W ENERGY PARTNERS LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year
Ended
December 31
2017
     Period from
May 31, 2016
(Inception)

through
December 31,
2016
 

Revenues:

     

Oil and natural gas sales

   $ 35,495,529      $ 9,226,743  

Operating Expenses:

     

Depletion, depreciation, amortization and impairment expense

     8,225,637        3,051,387  

Lease operating expense

     9,251,659        1,881,592  

Production taxes

     2,894,266        824,097  

General and administrative

     2,576,700        2,219,386  

Accretion expense

     11,325        2,295  
  

 

 

    

 

 

 

Total operating expenses

     22,959,587        7,978,757  

Operating Income

     12,535,942        1,247,986  

Other Income (Expense):

     

Interest income

     46,328        —    
  

 

 

    

 

 

 

Total other income

     46,328        —    
  

 

 

    

 

 

 

Net Income

   $ 12,582,270      $ 1,247,986  
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements.


W ENERGY PARTNERS LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL

Period from May 17, 2016 (Inception) through December 31, 2016

and Year Ended December 31, 2017

 

Balance at May 17, 2016 (Inception)

   $ —    

Contributions

     29,269,951  

Net income

     1,247,986  

Balance at December 31, 2016

     30,517,937  

Contributions

     65,354,852  

Net income

     12,582,270  
  

 

 

 

Balance at December 31, 2017

   $ 108,455,059  
  

 

 

 

See accompanying notes to consolidated financial statements.


W ENERGY PARTNERS LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     December 31,  
     2017     2016  

Operating Activities

    

Net income

   $ 12,582,270     $ 1,247,986  

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depletion, depreciation and amortization

     8,225,637       3,051,387  

Accretion expense

     11,325       2,295  

Changes in operating assets and liabilities:

    

Accounts receivable

     (7,685,689     (4,485,085

Due from affiliates

     132,029       (370,179

Prepaid expenses and other current assets

     18,808       (650,745

Accounts payable

     2,618,850       1,376,526  

Accrued liabilities

     172,561       896,584  
  

 

 

   

 

 

 

Net cash provided by operating activities

     16,075,791       1,068,769  

Investing Activities

    

Purchase of non oil and gas property and equipment

     (2,555     (4,667

Additions to oil and natural gas properties

     (78,789,552     (28,124,711
  

 

 

   

 

 

 

Net cash used in investing activities

     (78,792,107     (28,129,378

Financing Activities

    

Contributions

     65,354,852       29,269,951  
  

 

 

   

 

 

 

Net cash provided by financing activities

     65,354,852       29,269,951  
  

 

 

   

 

 

 

Net increase in cash and cash equivalents

     2,638,536       2,209,342  

Cash and cash equivalents at beginning of year/period

     2,209,342       —    
  

 

 

   

 

 

 

Cash and cash equivalents at end of year/period

   $ 4,847,878     $ 2,209,342  
  

 

 

   

 

 

 

Non-cash transactions:

    

Additions to oil and gas properties through accounts payable and accrued expenses

   $ 5,519,430     $ 1,326,318  
  

 

 

   

 

 

 

Additions to and acquired asset retirement obligations

   $ 230,717     $ 52,769  
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.


W ENERGY PARTNERS LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017 and 2016

A. Nature of Business

The accompanying consolidated financial statements include the accounts of W Energy Partners LLC and its wholly owned subsidiary WR Operating LLC (Collectively the “Company”). The Company is a Delaware limited partnership formed in May 2016 to purchase oil and gas non-operated working interests in producing and non-producing properties primarily in North Dakota. The Company began operations on May 17, 2016 (Inception).

B. Summary of Significant Accounting Policies

A summary of the Company’s significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows:

Basis of Accounting

The accounts are maintained and the consolidated financials have been prepared using accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, which are wholly-owned. Significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions. Significant assumptions are required in the valuation of proved oil and natural gas reserves, depreciation, depletion and amortization, and asset retirement obligations (“ARO”). Revisions to these estimates could be material.

Cash and Cash Equivalents

The Company considers all highly-liquid investments with an original maturity of three months or less to be cash equivalents. At December 31, 2017 and 2016, the Company had no such investments. The Company maintains deposits in one financial institution, which may at times exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses to amounts in excess of FDIC limits.

Accounts Receivable

Accounts receivable are stated at amounts management expects to collect from outstanding balances. The Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the Company’s oil and natural gas properties. Oil and natural gas revenue receivables are generally unsecured. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally


written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. As of December 31, 2017 and 2016, credit losses had not occurred and an allowance for doubtful accounts was not recorded.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk consists principally of cash, accounts receivable, and revenue.

The Company derived its revenue from operators in the oil and gas industry. These industry concentrations have the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that its operations could be affected by similar changes in economic, industry, or other conditions. However, the Company believes that the credit risk, posed by this industry concentration is offset by the creditworthiness of its operator base. For the year ended December 31, 2017, three operators accounts for approximately 80% of the Company’s revenue. For the period from May 17, 2016 (Inception) through December 31, 2016, two operators accounted for approximately 97% of the Company’s revenue.

Oil and Natural Gas Properties

The Company follows the full-cost method of accounting for its oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of oil and natural gas properties, including the cost of undeveloped leaseholds, dry holes, and leasehold equipment, are capitalized. All costs related to production activities, including workover costs, are charged to expense as incurred. Capitalized costs are depleted on a composite unit-of-production method based on proved oil and natural gas reserves.

Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the Company’s proved reserves. The Company had no significant sales during 2017 and 2016. The costs of unproved properties are excluded from depletion until the properties are evaluated. During 2017 and 2016, the Company had no unproved properties.

The remaining capitalized costs are subject to a “ceiling test”, which limits such costs to the aggregate of the “estimated present value”, discounted at a ten percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties.

Asset Retirement Obligations

The Company recognizes an ARO for legal obligations associated with the retirement of the Company’s oil and natural gas properties. Oil and natural gas producing companies incur such a liability upon acquiring or drilling a well. An ARO is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet which is depleted over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statements of operations. See further discussion of AROs at Note E.

Revenue Recognition

Oil and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its oil and natural gas revenues, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no significant imbalances at December 31, 2017 or 2016.


Fair Value Measurement

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-tier hierarchy that is used to identify assets and liabilities measured at fair value. The hierarchy focuses on the inputs used to measure fair value and requires that the lowest level input be used. The three levels defined are as follows:

 

   

Level 1—observable inputs that are based upon quoted market prices for identical assets or liabilities within active markets.

 

   

Level 2—observable inputs other than Level 1 that are based upon quoted market prices for similar assets or liabilities, based upon quoted prices within inactive markets, or inputs other than quoted market prices that are observable through market data for substantially the full term of the asset or liability.

 

   

Level 3—inputs that are unobservable for the particular asset or liability due to little or no market activity and are significant to the fair value of the asset or liability. These inputs reflect assumptions that market participants would use when valuing the particular asset or liability.

ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk free rate to be used and inflation rates. See Note E for the summary of changes in the fair value of the ARO for the years ended December 31, 2017 and 2016.

The carrying amounts approximate fair value due to the short maturity of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and other current liabilities.

The following table presents liabilities that are measured at fair value on a recurring basis at December 31:

 

     2017  
     Level 1      Level 2      Level 3      Total  

Liabilities

           

Asset retirement obligations

   $ —        $ —        $ 297,106      $ 297,106  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —        $ —        $ 297,106      $ 297,106  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     2016  
     Level 1      Level 2      Level 3      Total  

Liabilities

           

Asset retirement obligations

   $ —        $ —        $ 55,064      $ 55,064  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —        $ —        $ 55,064      $ 55,064  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Taxes

The Company is a pass-through entity for U.S. tax purposes. Under the existing provisions of the Internal Revenue Code, a pass-through entity is exempt from U.S. federal income tax other than tax on certain capital gains and passive income. The income or loss of a pass-through entity is passed through to the owners who include their share of the Company’s separately stated items of income, deduction, loss, and credit and their share of non-separately stated income or loss. Accordingly, no provision for U.S. federal income tax has been provided for the accompanying consolidated financial statements since the owners report their share of the Company’s taxable income or loss in their income tax return. Provisions for state taxes are based on the gross profit margin of the Company.

Tax returns related to 2016 and thereafter, remain open to possible examination by the tax authorities. No tax returns are currently under examination by any tax authorities. The Company did not incur any penalties or interest related to its federal tax returns during the years ended December 31, 2017 and 2016.


Adoption of New Accounting Standards

In January 2017 the Financial Accounting Standards Board (“FASB “) issued Accounting Standards Update (“ASU”) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The main objective of ASU 2017-01 is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments of this ASU provide a screen to determine when asset is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments of this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (ii) remove the evaluation of whether a market participant could replace missing elements. The Company adopted ASU 2017-01 on January 1, 2017, and the ASU will be applied prospectively to any acquisitions.

C. Asset Acquisitions

WM ND Energy Acquisition

During 2017 the Company acquired oil and natural gas properties from WM ND Energy Resources, LLC and WM ND Energy Resources II, LLC (“Waste Management Acquisition”). The purchase and sale agreement was signed on August 15, 2017, and the transaction closed on November 16, 2017, and the effective date of the transaction was March 1, 2017. The total purchase price for the Waste Management Acquisition was approximately $48.6 million after certain purchase price adjustments, which was funded by cash contributions from the members of the Company.

The purchase price was allocated to proved properties. The Company accounted for the acquisition using the purchase method as allowed by ASU 2017-01, which allowed for certain transactions to be accounted for as asset purchases.

D. Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at December 31,:

 

     2017      2016  

Leasehold costs

   $ 106,358,196      $ 25,711,343  

Lease and well equipment

     7,685,301        3,792,455  
  

 

 

    

 

 

 
     114,043,497        29,503,798  

Less accumulated depreciation, depletion, and amortization

     (11,274,573      (3,048,936
  

 

 

    

 

 

 
   $ 102,768,924      $ 26,454,862  
  

 

 

    

 

 

 

Capitalized costs are depleted on a composite unit-of-production method based on proved oil and natural gas reserves. For the year ended December 31, 2017 and the period from May 16, 2016 (Inception) through December 31, 2016, the Company recognized $8,225,637 and $3,048,936 of depletion expense, respectively.


E. Asset Retirement Obligations

The Company has evaluated 1,028 and 246 wells for the years ended December 31, 2017 and 2016, and has determined a range of abandonment dates through December 2069. The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31:

 

     2017      2016  

Asset retirement obligations at beginning of year/period

   $ 55,064      $ —    

Additions and acquired

     230,717        52,769  

Accretion of discount

     11,325        2,295  
  

 

 

    

 

 

 

Asset retirement obligations at end of year/period

   $ 297,106      $ 55,064  
  

 

 

    

 

 

 

F. Members’ Equity and Incentive Units

The following table summarizes the equity members and equity commitments as of December 31,2017:

 

Member

   Equity
Committed
     Equity
Percentage
 

Crestview W2 Holdings, L.P

   $ 150,000,000        95.63

Management Members

     500,000        .32

Additional Limited Partners

     6,350,000        4.05
  

 

 

    

 

 

 

Total

   $ 156,850,000        100
  

 

 

    

 

 

 

As of December 31, 2017, $94,624,803 of equity committed had been contributed.

Profits and losses will be determined and allocated with respect to each fiscal year of the Company as of the end of such fiscal year. Profits and losses will be allocated among the members in a manner such that the adjusted capital account of each member is nearly as possible, equal (proportionally) to the distributions that would be made to such member if the Company is dissolved.

The LLC agreement authorizes the Company to issue 100,000 incentive units. As of December 31, 2017, 94,350 incentive units were issued and outstanding to management members of the Company for services rendered. The incentive units are designed as a profits interest, and the incentive unit holders are entitled to an increased share of the distributable cash flow generated by the Company in the event that certain performance hurdles are met. Due to the profits interest nature of the incentive units, the units have no value at grant date. As such, no compensation expense was recorded during the year ended December 31, 2017, and period from May 16, 2017 (Inception) through December 31, 2016.

Distributions

The Company has sole discretion to determine the timing of any distributions and the aggregate amounts available for distribution. Distributions are made 100% to the Series A Unit holders until cumulative distributions to the holders total the amount of their capital contributions (“payout”). Thereafter, distributions are made 15% to the Series B Unit holders, and 85% to the Series A Unit holders until cumulative distributions have been made in an amount equal to 250% of the cumulative contributions. Thereafter, distributions are made 20% to the Series B Unit holders, and 80% to the Series A Unit holder until cumulative distributions have been made in an amount equal to 300% of the cumulative contributions. Thereafter, distributions are made 25% to the Series B Unit holders, and 75% to the Series A Unit holders.


G. Commitments and Contingencies

The Company leases its office space under an operating lease, which includes various renewal options and escalation clauses. Total rent expense for the year ended December 31, 2017, and the period from May 16, 2016 (Inception) through December 31, 2016 was $91,728 and $67,881, respectively.

Future minimum lease payments under non-cancelable operating leases as of December 31, 2017, are as follows:

 

2018

   $ 122,064  

2019

     125,991  

2020

     129,918  

2021

     133,845  

2022

     137,772  

Thereafter

     225,693  
  

 

 

 
   $ 875,283  
  

 

 

 

When the Company enters into an operating lease that contains a period where there are free or reduced rents, or rent increases throughout the lease term, then the Company recognizes rent expense on a straight-line basis over the term of the lease.

H. Related Party Transactions

In May 2016, the Company purchased capitalized leasehold costs in the amount of $1,860,020 from a related party.

During 2016, the Company entered into a management services agreement with a related party in which the related party is to reimburse the Company for 20% of overhead expenses through December 31, 2017, and 15% thereafter, subject to decrease based on certain situations. For the year ended December 31, 2017 and period from May 16, 2017 (Inception) through December 31, 2016, $472,054 and $370,179 in expenses were reimbursed, respectively. At December 31, 2017 and 2016, the Company had $238,150 and $370,719 in affiliate accounts receivable, respectively.

I. Subsequent Events

In preparing the accompanying consolidated financial statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through September 12, 2018, the date the consolidated financial statements were available for issuance.

In March 2018, the Company entered into a revolving line of credit (“Line of Credit”) with a bank with an initial borrowing base of $30,000,000. The Line of Credit is secured by oil and natural gas properties, and has a maturity date of March 29, 2022. The Fund has drawn on $9,000,000 subsequent to year end.

The Company may elect that borrowings be comprised of any combination of base rate portion or London interbank rate portion (“LIBOR”) with minimum borrowings for base rate portion being $250,000, and minimum borrowings for LIBOR portion being $500,000.

The Company pays interest on the unpaid principal amount of each loan until such principal amount is repaid in full. Interest on the loans is determined as follows:

 

   

With respect to the base rate portion, interest is determined by the highest of a) prime rate which is determined by the Wall Street Journal, b) sum of the federal funds rate plus .50%, and c) adjusted LIBOR for such interest period plus 1.00%, plus an applicable margin ranging from 0.50% to 1.50% per annum, determined by the percentage of the conforming borrowing base then in effect that is drawn, or


   

With respect to LIBOR portion, adjusted LIBOR plus an applicable margin ranging from 2.50% to 3.50% per annum, determined by the percentage of the conforming borrowing base then in effect that is drawn.

In addition, the Company pays a commitment fee ranging from 0.50% to 0.375% determined by the percentage of the conforming borrowing base then in effect that is drawn. These commitment fees are also considered interest expense.

In July 2018, the Company entered into a purchase sale agreement to sell all assets of the Company for consideration of $100 million and 56.37 million shares of the acquiring company.

J. Supplemental Oil and Natural Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion, and amortization are as follows at the dates indicated:

 

     Year/Period Ended
December 31
 
     2017      2016  
     (In Thousands)  

Proved oil and natural gas properties(1)

   $ 114,043      $ 29,504  

Accumulated depletion, depreciation, and amortization

     (11,275      (3,049

Total

   $ 102,768      $ 26,455  
  

 

 

    

 

 

 

 

(1)

Amounts include a total of $0.3 million and $0.1 million of asset retirement cost at December 31, 2017 and 2016, respectively.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities

Costs incurred in property acquisition, exploration, and development activities were as follows for the periods indicated:

 

     Year/Period Ended
December 31
 
     2017      2016  
     (In Thousands)  

Leasehold costs, proved

   $ 66,946      $ 8,068  

Proved development costs

     47,097        21,436  
  

 

 

    

 

 

 

Total

   $ 114,043      $ 29,504  
  

 

 

    

 

 

 

Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

As required by the FASB and Securities and Exchange Commission (“SEC”), the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates, and a discount factor of 10% to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and natural gas properties or of the value of its proved oil and


natural gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience 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.

The Company’s internal reservoir engineer prepared the reserves estimates as of December 31, 2017 and 2016. All proved reserves are located in the United States, and all prices are held constant in accordance with SEC rules.

The weighted average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December adjusted for quality adjustments, transportation fees, and regional price differences.

 

     2017      2016  

Oil ($/Bb1)

   $ 42.33      $ 37.75  

WTI, adjusted

     

Gas/Liquids ($/Bbl)

     

WTI adjusted

   $ 4.48      $ 3.72  


The following tables set forth estimates of the net reserves as of December 31:

 

     2016  
     Oil (MBbl)      Gas (BOE)      Total BOE  

Proved developed and undeveloped reserves

        

Beginning of period

     —          —          —    

Extensions and discoveries

     —          —          —    

Acquisitions

     1,517        760        2,277  

Production

     (187      (48      (235

Revision of previous estimates

     —          —          —    
  

 

 

    

 

 

    

 

 

 

End of period

     1,330        712        2,042  
  

 

 

    

 

 

    

 

 

 

Proved developed reserves

        

Beginning of period

     —          —          —    

End of period

     1,330        712        2,042  

Proved undeveloped reserves

        

Beginning of period

     —          —          —    

End of period

     —          —          —    

 

     2017  
     Oil (MBbl)      Gas (BOE)      Total BOE  

Proved developed and undeveloped reserves

        

Beginning of period

     1,330        712        2,042  

Extensions and discoveries

     2,153        538        2,691  

Acquisitions

     10,023        2,772        12,795  

Production

     (582      (275      (857

Revision of previous estimates

     14        9        23  
  

 

 

    

 

 

    

 

 

 

End of period

     12,938        3,756        16,694  
  

 

 

    

 

 

    

 

 

 

Proved developed reserves

        

Beginning of period

     1,330        712        2,042  

End of period

     10,785        3,218        14,003  

Proved undeveloped reserves

        

Beginning of period

     —          —          —    

End of period

     2,153        538        2,691  

The Company was formed on May 17, 2016, and initially had no oil and gas assets. Through 2017 and 2016, certain acquisitions were made resulting in proved oil and gas reserves.

In 2017 the revision of previous estimates was the result of a 12% increase in the SEC average realized price for 2017 from 2016, offset by a negative revision in assumptions for terminal well decline and other operating expenses.

In 2017 extensions and discoveries were a result of analysis by the Company that found drilling permits filed in active areas which caused us to identify a number of PUD locations.

A variety of methodologies is used to determine our proved reserve estimates. The primary methodologies are decline curve analysis, production type curve analysis, statistical modelling, and reservoir simulation. A combination of some or all of these methods is used to determine the reserves estimates for all properties.


The standardized measure of discounted future net cash flows from proved reserves is as follows:

 

     Year/Period Ended
December 31
 
     2017      2016  
     (In Thousands)  

Future cash inflows

   $ 648,643      $ 66,107  

Future production costs

     (233,791      (30,975

Future development costs

     (57,217      —    

Future income tax expense(1)

     —          —    
  

 

 

    

 

 

 

Future net cash flows for estimated timing of cash flows

     357,635        35,132  

10% annual discount for estimated timing of cash flows

     (183,833      (14,203
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 173,802      $ 20,929  
  

 

 

    

 

 

 

 

(1)

We are a pass-through entity for tax purposes. Accordingly, we have excluded the impact of tax from this analysis.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during the year/period ended December 31:

 

     2017      2016  
     (In Thousands)  

Beginning of year/period

   $ 20,929      $ —    

Purchase of minerals in place

     133,213        23,341  

Sale of oil and natural gas products, net of production costs

     (23,350      (6,521

Extensions and discoveries

     28,019        —    

Changes in prices and costs

     2,594        —    

Net changes in future development costs

     —          —    

Previously estimated future development costs incurred during the period

     —       

Revisions of previous quantities

     231        —    

Accretion of discount

     14,631        2,334  

Other

     (2,465      1,775  
  

 

 

    

 

 

 

End of year/period

   $ 173,802      $ 20,929  
  

 

 

    

 

 

 
EX-99.3

Exhibit 99.3

W ENERGY PARTNERS LLC

CONSOLIDATED BALANCE SHEETS

 

     June 30,
2018
    December 31,
2017
 
Assets    (Unaudited)        

Current assets:

    

Cash and cash equivalents

   $ 1,590,167     $ 4,847,878  

Accounts receivable

     10,041,570       12,170,774  

Due from affiliates

     104,430       238,150  

Prepaid expenses and other current assets

     390,620       631,937  
  

 

 

   

 

 

 

Total current assets

     12,126,787       17,888,739  

Oil and natural gas properties (full-cost accounting):

    

Proved oil and natural gas properties

     155,969,595       114,043,497  

Accumulated depletion, depreciation and amortization

     (20,946,226     (11,274,573
  

 

 

   

 

 

 

Total oil and natural gas properties, net

     135,023,369       102,768,924  

Non oil and gas property and equipment, net

     4,771       4,771  
  

 

 

   

 

 

 

Total assets

   $ 147,154,927     $ 120,662,434  
  

 

 

   

 

 

 

Liabilities and Members’ Capital

    

Current liabilities:

    

Accounts payable

   $ 10,259,890     $ 10,841,124  

Accrued liabilities

     —         1,069,145  
  

 

 

   

 

 

 

Total current liabilities

     10,259,890       11,910,269  

Line of credit

     9,000,000       —    

Asset retirement obligations, long-term

     317,880       297,106  
  

 

 

   

 

 

 

Total liabilities

     19,577,770       12,207,375  

Commitments and contingencies

    

Members’ capital

     127,577,157       108,455,059  
  

 

 

   

 

 

 

Total liabilities and members’ capital

   $ 147,154,927     $ 120,662,434  
  

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.


W ENERGY PARTNERS LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended      Six Months Ended  
     June 30, 2018     June 30, 2017      June 30, 2018     June 30, 2017  

Revenues:

         

Oil and natural gas sales

   $ 23,416,931     $ 6,699,280      $ 41,415,688     $ 14,335,823  

Operating Expenses:

         

Depletion, depreciation and amortization expense

     5,844,120       1,078,060        9,671,653       2,043,821  

Lease operating expense

     5,006,615       1,874,256        9,089,089       3,664,998  

Production taxes

     1,256,566       555,812        2,430,449       1,179,807  

General and administrative

     706,639       599,507        1,158,008       1,170,001  

Accretion expense

     4,507       1,121        8,795       2,202  
  

 

 

   

 

 

    

 

 

   

 

 

 

Total operating expenses

     12,818,447       4,108,756        22,357,994       8,060,829  
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating Income

     10,598,484       2,590,524        19,057,694       6,274,994  

Other Income (Expense)

         

Interest expense

     (76,267     —          (76,267     —    

Interest income

     2       —          4       —    
  

 

 

   

 

 

    

 

 

   

 

 

 

Total other expense

     (76,265     —          (76,263     —    
  

 

 

   

 

 

    

 

 

   

 

 

 

Net Income

   $ 10,522,219     $ 2,590,524      $ 18,981,431     $ 6,274,994  
  

 

 

   

 

 

    

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.


W ENERGY PARTNERS LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended June 30,  
     2018     2017  

Operating Activities

    

Net income

   $ 18,981,431     $ 6,274,994  

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depletion, depreciation and amortization expense

     9,671,653       2,043,821  

Changes in operating assets and liabilities:

     8,795       2,202  

Accounts receivable

     2,129,204       (571,197

Due from affiliates

     133,720       118,439  

Prepaid expenses and other current assets

     241,317       (101,706

Accounts payable

     (581,234     155,253  

Accruals

     (1,069,145     (362,012
  

 

 

   

 

 

 

Net cash provided by operating activities

     29,515,741       7,559,794  

Investing Activities

    

Purchase of non oil and gas property and equipment

     —         (5,005

Additions to oil and natural gas properties

     (41,914,119     (18,522,173
  

 

 

   

 

 

 

Net cash used in investing activities

     41,914,119     (18,527,178

Financing Activities

    

Contributions

     140,667       15,662,449  

Proceeds from line of credit

     9,000,000       —    
  

 

 

   

 

 

 

Net cash provided by financing activities

     9,140,667       15,662,449  
  

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

     (3,257,711     4,695,065  

Cash and cash equivalents at beginning of period

     4,847,878       2,209,342  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 1,590,167     $ 6,904,407  
  

 

 

   

 

 

 

Non-cash transactions:

    

Additions to an acquired asset retirement obligations

   $ 11,979     $ 22,503  
  

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.


W ENERGY PARTNERS LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018 and December 31, 2017

 

A.

Nature of Business

The accompanying consolidated financial statements include the accounts of W Energy Partners LLC and its wholly owned subsidiary WR Operating LLC (Collectively the “Company”). The Company is a Delaware limited partnership formed in May 2016 to purchase oil and gas non-operated working interests in producing and non-producing properties primarily in North Dakota. The Company began operations on May 17, 2016 (Inception).

 

B.

Summary of Significant Accounting Policies

A summary of the Company’s significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows:

Basis of Accounting

The accounts are maintained and the consolidated financials have been prepared using accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, which are wholly-owned. Significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions. Significant assumptions are required in the valuation of proved oil and natural gas reserves, depreciation, depletion and amortization, and asset retirement obligations (“ARO”). Revisions to these estimates could be material.

Cash and Cash Equivalents

The Company considers all highly-liquid investments with an original maturity of three months or less to be cash equivalents. At June 30, 2018 and December 31, 2017, the Company had no such investments. The Company maintains deposits in two financial institutions, which may at times exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses to amounts in excess of FDIC limits.

Accounts Receivable

Accounts receivable are stated at amounts management expects to collect from outstanding balances. The Company’s accounts receivable are due from purchasers of oil and natural gas or operators of the Company’s oil and natural gas properties. Oil and natural gas revenue receivables are generally unsecured. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally


written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. As of June 30, 2018 and December 31, 2017, credit losses had not occurred and an allowance for doubtful accounts was not recorded.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk consists principally of cash, accounts receivable, and revenue.

The Company derived its revenue from operators in the oil and gas industry. These industry concentrations have the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that its operations could be affected by similar changes in economic, industry, or other conditions. However, the Company believes that the credit risk, posed by this industry concentration is offset by the creditworthiness of its operator base. For the three and six month periods ended June 30, 2018, three operators accounts for approximately 80% and 76% of the Company’s revenue, respectively. For the three and six month periods ended June 30, 2017, three operators accounts for approximately 60% and 74% of the Company’s revenue, respectively.

Oil and Natural Gas Properties

The Company follows the full-cost method of accounting for its oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of oil and natural gas properties, including the cost of undeveloped leaseholds, dry holes, and leasehold equipment, are capitalized. All costs related to production activities, including workover costs, are charged to expense as incurred. Capitalized costs are depleted on a composite unit-of-production method based on proved oil and natural gas reserves.

Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the Company’s proved reserves. The Company had no significant sales during the period ended June 30, 2018 and 2017. The costs of unproved properties are excluded from depletion until the properties are evaluated. During the period ended June 30, 2018 and the year ended December 31, 2017, the Company had no unproved properties.

The remaining capitalized costs are subject to a “ceiling test”, which limits such costs to the aggregate of the “estimated present value”, discounted at a ten percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties.

Asset Retirement Obligations

The Company recognizes an ARO for legal obligations associated with the retirement of the Company’s oil and natural gas properties. Oil and natural gas producing companies incur such a liability upon acquiring or drilling a well. An ARO is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet which is depleted over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statements of operations. See further discussion of AROs at Note D.

Revenue Recognition

Oil and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its oil and natural gas revenues, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no significant imbalances at June 30, 2018 and December 31, 2017.


Fair Value Measurement

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-tier hierarchy that is used to identify assets and liabilities measured at fair value. The hierarchy focuses on the inputs used to measure fair value and requires that the lowest level input be used. The three levels defined are as follows:

 

   

Level 1—observable inputs that are based upon quoted market prices for identical assets or liabilities within active markets.

 

   

Level 2—observable inputs other than Level 1 that are based upon quoted market prices for similar assets or liabilities, based upon quoted prices within inactive markets, or inputs other than quoted market prices that are observable through market data for substantially the full term of the asset or liability.

 

   

Level 3—inputs that are unobservable for the particular asset or liability due to little or no market activity and are significant to the fair value of the asset or liability. These inputs reflect assumptions that market participants would use when valuing the particular asset or liability.

ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk free rate to be used and inflation rates. See Note D for the summary of changes in the fair value of the ARO for the period ended June 30, 2018 and the year ended December 31, 2017.

The carrying amounts approximate fair value due to the short maturity of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and other current liabilities.

The following table presents liabilities that are measured at fair value on a recurring basis at June 30, 2018:

 

     Level 1      Level 2      Level 3      Total  

Liabilities

           

Asset retirement obligations

   $ —        $ —        $ 317,880      $ 317,880  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —        $ —        $ 317,880      $ 317,880  
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table presents liabilities that are measured at fair value on a recurring basis at December 31, 2017:

 

     Level 1      Level 2      Level 3      Total  

Liabilities

           

Asset retirement obligations

   $ —        $ —        $ 297,106      $ 297,106  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —        $ —        $ 297,106      $ 297,106  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Taxes

The Company is a pass-through entity for U.S. tax purposes. Under the existing provisions of the Internal Revenue Code, a pass-through entity is exempt from U.S. federal income tax other than tax on certain capital gains and passive income. The income or loss of a pass-through entity is passed through to the owners who include their share of the Company’s separately stated items of income, deduction, loss, and credit and their share of non-separately stated income or loss. Accordingly, no provision for U.S. federal income tax has been provided for the accompanying consolidated financial statements since the owners report their share of the Company’s taxable income or loss in their income tax return. Provisions for state taxes are based on the gross profit margin of the Company.


Tax returns related to 2016 and thereafter, remain open to possible examination by the tax authorities. No tax returns are currently under examination by any tax authorities. The Company did not incur any penalties or interest related to its federal tax returns during the period ended June 30, 2018 and 2017.

 

C.

Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at June 30, 2018 and December 31, 2017:

 

     2018      2017  

Leasehold costs

   $ 143,509,442      $ 106,358,196  

Lease and well equipment

     12,460,153        7,685,301  
  

 

 

    

 

 

 
     155,969,595        114,043,497  

Less accumulated depreciation, depletion, and amortization

     (20,946,226      (11,274,573
  

 

 

    

 

 

 
   $ 135,023,369      $ 102,768,924  
  

 

 

    

 

 

 

Capitalized costs are depleted on a composite unit-of-production method based on proved oil and natural gas reserves. For the three and six month period ended June 30, 2018, the Company recognized $5,844,120 and $9,671,653 of depletion expense, respectively. For the three and six month period ended June 30, 2017, the Company recognized $1,078,060 and $2,043,821 of depletion expense, respectively.

 

D.

Asset Retirement Obligations

The Company has evaluated 1,076 and 1028 wells for the period ended June 30, 2018 and for the year ended December 31, 2017, and has determined a range of abandonment dates through December 2069. The following table summarizes the changes in the Company’s asset retirement obligations as of June 30, 2018 and December 31, 2017:

 

     2018      2017  

Asset retirement obligations at beginning of year/period

   $ 297,106      $ 55,064  

Additions and acquired

     11,979        230,717  

Accretion of discount

     8,795        11,325  
  

 

 

    

 

 

 

Asset retirement obligations at end of year/period

   $ 317,880      $ 297,106  
  

 

 

    

 

 

 

For the three and six month period ended June 30, 2018, the Company recognized $4,507 and $8,795 of accretion expense, respectively. For the three and six month period ended June 30, 2017, the Company recognized $1,121 and $2,202 of accretion expense, respectively.

 

E.

Members’ Equity and Incentive Units

The following table summarizes the equity members and equity commitments as of June 30, 2018:

 


Member

   Equity
Committee
     Equity
Percentage
 

Crestview W2 Holdings, L.P

   $ 150,000,000        95.63

Management Members

     500,000        .32

Additional Limited Partners

     6,350,000        4.05
  

 

 

    

 

 

 

Total

   $ 156,850,000        100
  

 

 

    

 

 

 


As of June 30, 2018, $94,624,805 of equity committed had been contributed.

Profits and losses will be determined and allocated with respect to each fiscal year of the Company as of the end of such fiscal year. Profits and losses will be allocated among the members in a manner such that the adjusted capital account of each member is nearly as possible, equal (proportionally) to the distributions that would be made to such member if the Company is dissolved.

The LLC agreement authorizes the Company to issue 100,000 incentive units. As of June 30, 2018, 94,350 incentive units were issued and outstanding to management members of the Company for services rendered. The incentive units are designed as a profits interest, and the incentive unit holders are entitled to an increased share of the distributable cash flow generated by the Company in the event that certain performance hurdles are met. Due to the profits interest nature of the incentive units, the units have no value at grant date. As such, no compensation expense was recorded during the three and six month periods ended June 30, 2018 and 2017.

Distributions

The Company has sole discretion to determine the timing of any distributions and the aggregate amounts available for distribution. Distributions are made 100% to the Series A Unit holders until cumulative distributions to the holders total the amount of their capital contributions (“payout”). Thereafter, distributions are made 15% to the Series B Unit holders, and 85% to the Series A Unit holders until cumulative distributions have been made in an amount equal to 250% of the cumulative contributions. Thereafter, distributions are made 20% to the Series B Unit holders, and 80% to the Series A Unit holder until cumulative distributions have been made in an amount equal to 300% of the cumulative contributions. Thereafter, distributions are made 25% to the Series B Unit holders, and 75% to the Series A Unit holders.

 

F.

Commitments and Contingencies

The Company leases its office space under an operating lease, which includes various renewal options and escalation clauses. Total rent expense for the three and six month periods ended June 30, 2018 was $56,903 and $104,989, respectively. Total rent expense for the three and six month periods ended June 30, 2017 was $45,000 and $45,000, respectively.

Future minimum lease payments under non-cancelable operating leases as of June 30, 2018, are as follows:

 

2018

   $ 61,850  

2019

     125,991  

2020

     129,918  

2021

     133,845  

2022

     137,772  

Thereafter

     225,693  
  

 

 

 
   $ 815,069  
  

 

 

 

When the Company enters into an operating lease that contains a period where there are free or reduced rents, or rent increases throughout the lease term, then the Company recognizes rent expense on a straight-line basis over the term of the lease.

 

G.

Related Party Transactions

During 2016, the Company entered into a management services agreement with a related party in which the related party is to reimburse the Company for 20% of overhead expenses through December 31, 2017, and 15% thereafter, subject to decrease based on certain situations. For the three and six month periods ended June 30,


2018 $106,399 and $177,992 in expenses were reimbursed, respectively. For the three and six month periods ended June 30, 2018 $132,137 and $263,845 in expenses were reimbursed, respectively. At June 30, 2018 and December 31, 2017, the Company had $104,430 and $238,150, respectively, in affiliate accounts receivable.

 

H.

Subsequent Events

I n July 2018, the Company entered into a purchase sale agreement to sell all assets of the Company for consideration of $100 million and 56.37 million shares of the acquiring company.

EX-99.4

Exhibit 99.4

Independent Auditors’ Report

To the Board of Managers of

Northern Oil and Gas, Inc.

We have audited the accompanying statement of revenues and direct operating expenses (the financial statement), which comprise the revenues and direct operating expenses of certain oil and gas properties from Pivotal Williston Basin, LP and Pivotal Williston Basin II, LP (collectively, the Partnership), for the year ended December 31, 2017 and the related notes to the financial statement.

Management’s Responsibility for the Financial Statement

Management is responsible for the preparation and fair presentation of this financial statement in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statement that is free of material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Financial Statement is free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statement. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statement in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statement.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statement referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Partnership for the year ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

The accompanying financial statement referred to above was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Accordingly, the financial statement is not intended to be a complete presentation of the operations of the Partnership.

/s/ WEAVER AND TIDWELL, L.L.P.

Dallas, Texas

September 12, 2018


Pivotal Williston Basin, LP & Pivotal Williston Basin II, LP

Statement of Revenues and Direct Operating Expenses

 

     Year Ended
December 31, 2017
 

Revenues

  

Oil and natural gas revenues

   $ 50,047,098  
  

 

 

 

Total Revenues

     50,047,098  
  

 

 

 

Direct Operating Expenses

  

Lease operating expense

     8,352,270  

Transportation

     3,853,464  

Ad Valorem

     1,634  

Production taxes

     4,307,119  
  

 

 

 

Total Direct Operating Expenses

     16,514,487  
  

 

 

 

Revenues in excess of direct operating expenses

   $ 33,532,611  
  

 

 

 

See accompanying notes to the Statement of Revenues and Direct Operating Expenses


Pivotal Williston Basin, LP & Pivotal Williston Basin II, LP

Statements of Revenues and Direct Operating Expenses

 

     Six Months Ended June 30,
2018
     Six Months Ended June 30,
2017
 
     (unaudited)      (unaudited)  

Revenues

     

Oil and natural gas revenues

   $ 30,217,195      $ 27,729,856  
  

 

 

    

 

 

 

Total Revenues

     30,217,195        27,729,856  
  

 

 

    

 

 

 

Direct Operating Expenses

     

Lease operating expense

     3,465,597        5,134,965  

Transportation

     1,498,635        2,655,350  

Ad Valorem

     —          1,634  

Production taxes

     2,757,243        2,518,046  
  

 

 

    

 

 

 

Total Direct Operating Expenses

     7,721,475        10,309,995  
  

 

 

    

 

 

 

Revenues in excess of direct operating expenses

   $ 22,495,720      $ 17,419,861  
  

 

 

    

 

 

 

See accompanying notes to the Statement of Revenues and Direct Operating Expenses


PIVOTAL BASIN LP & PIVOTAL BASIN II, LP

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

 

1.

Basis of Presentation

On July 17, 2018, Pivotal Williston Basin, LP and Pivotal Williston Basin II, LP (“Pivotal”) entered into a purchase and sale agreement (the “PSA”) to sell to Northern Oil and Gas Inc. (“Northern”) its working interest in the Pivotal Williston Basin assets (the “Pivotal working interest”) for a total of $68.4 million in cash and $83.6 million in Northern Oil and Gas Inc. common stock, subject to customary purchase price adjustments. The PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to closing. The parties expect that the transaction will close on September 15, 2018 and will be effective as of June 1, 2018.

The accompanying audited statement include revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Pivotal Williston Basin, LP and Pivotal Williston Basin II, LP working interest. The accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Pivotal working interest including, but not limited to, general and administrative expenses, interest expense and federal and state income tax expenses. These costs were not separately allocated to the Pivotal working interest in the accounting records. Furthermore, no balance sheet has been presented for the Pivotal working interest because the divested properties were not accounted for as a separate subsidiary or division of Pivotal and complete financial statements are not available, nor has information about the Pivotal working interest’s operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Pivotal working interest are presented in lieu of the full financial statements required under Item 305 of Securities and Exchange Commission (“SEC”) Regulation S-X.

These Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Pivotal working interest on a go forward basis.

 

2.

Summary of Significant Accounting Policies

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that the reported amounts of revenues and expenses during the reporting period and in disclosure of contingencies.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

Direct Operating Expenses—Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Pivotal working interest. The direct operating expenses include lease operating, processing and transportation expenses, and production taxes.

 

3.

Commitments and Contingencies

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant


markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future.

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments, as discussed above. The Company depends on cash flows from operating activities, member contributions and, as necessary, borrowings to fund its capital expenditures.

 

4.

Subsequent Events

The Company has evaluated subsequent events through September 12, 2018, the date the statements of revenue and direct expenses were available to be issued.

Supplemental reserve information (Unaudited)

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof for the year ended December 31, 2017 attributable to the Pivotal working interest. All of the reserves are located in the United States. The following table sets forth certain information with respect to the reserves attributable to the Pivotal working interest for 2017. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Pivotal working interest. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to prove properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Pivotal working interest and any adjustments in the projected economic life of such property resulting from changes in product prices.

Estimated quantities of oil, NGL and natural gas reserves

The following table sets forth certain data pertaining to the Pivotal working interest’s proved, proved developed and proved undeveloped reserves for the year ended on December 31, 2017:

 

Year Ended December 31, 2017

   Oil (Bbl)     Gas (Mcf)     Liquids (Bbl)     MCFE     BOE  

Beginning of period proved reserves

     5,701,888       4,926,571       156,622       40,077,631       6,679,605  

Revisions

     753,512       1,954,448       427,264       9,039,104       1,506,517  

Acquisition of reserves

     104,298       187,487       29,250       988,775       164,796  

Production

     (994,870     (1,012,660     (115,598     (7,675,468     (1,279,245
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total proved reserves, end of period

     5,564,828       6,055,846       497,538       42,430,042       7,071,673  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved developed reserves

     5,564,828       6,055,846       497,538       42,430,042       7,071,673  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves

     —         —         —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


Standardized Measure of Discounted Future Net Cash Flows

The Standard Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil and natural gas reserves is presented below:

 

Year Ended December 31, 2017

   Pretax Amount      Taxes      After Tax Amount  

Future cash inflows (total revenues)

   $ 297,878,878        —        $ 297,878,878  

Future production costs (severance and ad valorem taxes plus LOE

     (141,447,584      —          (141,447,584

Future development costs (capital costs)

     (14,675,061      —          (14,675,061

Future net cash flows

     141,756,233        —          141,756,233  

10% annual discount for estimated timing of cash flows

     (49,542,200      —          (49,542,200
  

 

 

    

 

 

    

 

 

 

Standardized measure of discounted future net cash flows (DFNCF)

   $ 92,214,033        —        $ 92,214,033  
  

 

 

    

 

 

    

 

 

 

Changes in Standardized Measures

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated:

 

Year Ended December 31, 2017

   December 31, 2017  

Standardized Measure Balance, beginning of year

   $ 62,615,568  

Net change in prices and production costs

     27,236,549  

Net change in future development costs

     3,173,744  

Oil and Gas net revenue

     (33,532,610

Acquisition of reserves

     2,328,644  

Revisions of previous quantity estimates

     19,789,509  

Previously estimated development costs incurred

     2,589,981  

Accretion of discount

     6,261,557  

Changes in timing and other

     1,751,091  
  

 

 

 

Standardized Measure Balance, end of year

   $ 92,214,033