Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

 

x Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the quarterly period ended September 30, 2014

Or

 

¨ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the transition period from                      to                     

Commission File Number 33-16820-D

 

 

ARÊTE INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Colorado   84-1508638

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

7260 Osceola Street, Westminster, Colorado   80030
(Address of Principal Executive Offices)   (Zip Code)

303-427-8688

(Registrant’s Telephone Number, Including Area Code)

 

 

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

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

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   x

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

As of November 17, 2014, the Registrant had 12,408,459 shares of common stock issued and outstanding.

 

  (1) Explanatory Note: The Company is a voluntary filer with the Securities & Exchange Commission but it has filed all Exchange Act reports for the preceding 12 months.

 

 

 


Table of Contents

ARÊTE INDUSTRIES, INC.

Table of Contents

 

         Page  

Part 1 - Financial Information

  

Item 1 -

 

Financial Statements

     3   

Item 2 -

 

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

     14   

Item 3 -

 

Quantitative and Qualitative Disclosures about Market Risk

     26   

Item 4 -

 

Controls and Procedures

     26   

Part 2 - Other Information

  

Item 1 -

 

Legal Proceedings

     27   

Item 2 -

 

Unregistered Sales of Equity Securities and Use of Proceeds

     27   

Item 3 -

 

Defaults upon Senior Securities

     27   

Item 4 -

 

Mine Safety Disclosures

     27   

Item 5 -

 

Other Information

     27   

Item 6 –

 

Exhibits

     27   

Signatures

     28   


Table of Contents

Part 1 – FINANCIAL INFORMATION

Item 1 - Financial Statements

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2013 and September 30, 2014

 

     2013     2014  
ASSETS     

Current Assets:

    

Cash and equivalents

   $ 476,323      $ 2,920   

Receivable from DNR Oil & Gas, Inc.:

    

Oil and gas sales, net of production costs

     230,029        383,746   

Other

     2,368        108,574   

Prepaid expenses and other

     38,177        45,391   
  

 

 

   

 

 

 

Total Current Assets

     746,897        540,631   
  

 

 

   

 

 

 

Property and Equipment:

    

Oil and gas properties, at cost, successful efforts method:

    

Proved properties

     9,555,897        10,041,921   

Unevaluated properties

     314,336        314,336   

Natural gas gathering system

     442,195        442,195   

Furniture and equipment

     22,522        22,522   
  

 

 

   

 

 

 

Total property and equipment

     10,334,950        10,820,974   

Less accumulated depreciation, depletion and amortization

     (2,094,337     (2,580,398
  

 

 

   

 

 

 

Net Property and Equipment

     8,240,613        8,240,576   
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 8,987,510      $ 8,781,207   
  

 

 

   

 

 

 

 

3


Table of Contents

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

December 31, 2013 and September 30, 2014

 

     2013     2014  
LIABILITIES AND STOCKHOLDERS’ EQUITY     

Current Liabilities:

    

Accounts payable:

    

Payable to DNR Oil & Gas, Inc.:

    

Operator fees and other

     36,000        36,000   

Unrelated parties

     17,806        100,874   

Notes and advances payable - current portion:

    

Directors and affiliates

     717,833        296,033   

Unrelated parties

     325,000        933,105   

Accrued interest expense

     52,242        20,507   

Accrued consulting - related party

     —          8,750   

Director fees payable in common stock

     450        10,900   

Current portion of asset retirement obligations

     159,782        154,398   

Other accrued costs and expenses

     57,210        98,125   
  

 

 

   

 

 

 

Total Current Liabilities

     1,366,323        1,658,692   
  

 

 

   

 

 

 

Long-Term Liabilities:

    

Contingent acquisition costs payable to DNR Oil & Gas, Inc.

     250,000        250,000   

Notes and advances payable, net of current portion:

    

DNR Oil & Gas, Inc.

     792,151        792,151   

Directors and affiliates

     246,639        102,714   

Unrelated parties

     425,000        31,000   

Asset retirement obligations, net of current portion

     522,421        541,267   
  

 

 

   

 

 

 

Total Long-Term Liabilities

     2,236,211        1,717,132   
  

 

 

   

 

 

 

Total Liabilities

     3,602,534        3,375,824   
  

 

 

   

 

 

 

Commitments and Contingencies

    

Stockholders’ Equity:

    

Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:

    

Series 1; authorized 30,000 shares, issued and outstanding 10 shares in 2013 and 0 shares 2014, liquidation preference of $111,250 in 2013 and of $0 in 2014

     95,451        —     

Series 2; authorized 2,500 shares, no shares issued and outstanding in 2013 and 2014

     —          —     

Common stock, no par value; authorized 499,000,000 shares, issued and outstanding 13,608,459 in 2013 and 12,408,459 in 2014

     21,488,387        21,260,387   

Accumulated deficit

     (16,198,862     (15,855,004
  

 

 

   

 

 

 

Total Stockholders’ Equity

     5,384,976        5,405,383   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 8,987,510      $ 8,781,207   
  

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

4


Table of Contents

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

Three and Nine Months Ended September 30, 2013 and 2014

 

     Quarter Ended September 30:     Nine-Months Ended September 30  
     2013     2014     2013     2014  

Revenues:

        

Oil and natural gas sales

   $ 664,206        555,984      $ 1,638,218      $ 1,721,223   

Sale of oil and natural gas properties

     27,500        108,479        28,449        350,951   

Royalty revenue

     553        755        533        2,525   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     692,259        665,218        1,667,200        2,074,699   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating Expenses:

        

Oil and gas producing activities:

        

Lease operating expenses

     187,126        196,134        528,526        566,068   

Production taxes

     58,586        52,245        135,451        143,891   

Depreciation, depletion, amortization and accretion

     209,611        210,335        532,946        502,180   

Gas gathering:

        

Operating expenses

     3,543        609        11,228        7,979   

Depreciation

     11,055        11,055        33,165        33,165   

General and administrative expenses:

        

Director fees

     450        10,000        1,800        10,450   

Investor relations

     10,922        2,448        86,349        37,634   

Legal, auditing and professional services

     21,580        37,109        118,470        115,753   

Consulting and executive services:

        

Related parties

     30,750        41,250        92,250        168,750   

Other administrative expenses

     3,653        18,084        44,215        59,166   

Depreciation

     142        143        427        428   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     537,418        579,412        1,584,827        1,645,464   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     154,841        85,806        82,373        429,235   

Other income (expense):

        

Interest income

     —          —          1        —     

Interest expense

     (36,693     (33,350     (98,493     (103,328
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     118,148        52,456        (16,119     325,907   

Income tax benefit (expense)

     —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 118,148      $ 52,456      $ (16,119   $ 325,907   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Income Applicable to Common Stockholders:

        

Net Income (loss)

   $ 118,148        52,456      $ (16,119   $ 325,907   

Redemption of preferred stock

     106,661        17,951        3,160,026        17,951   

Accrued preferred stock dividends

     (3,750     (1,875     (209,063     (9,375
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) applicable to common stockholders

   $ 221,059      $ 68,532      $ 2,934,844      $ 334,483   
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings (Loss) Per Share Applicable to Common Stockholders:

        

Basic

   $ 0.02      $ 0.01      $ 0.30      $ 0.03   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

   $ 0.02      $ 0.01      $ 0.22      $ 0.03   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted Average Number of Common Shares Outstanding:

        

Basic

     13,400,000        12,408,000        9,850,000        12,532,000   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     13,451,466        12,408,000        13,451,466        12,532,000   
  

 

 

   

 

 

   

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

5


Table of Contents

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Nine Months Ended September 30, 2014

 

     Class A Preferred Stock     Common Stock     Accumulated        
     Shares     Amount     Shares     Amount     Deficit     Total  

Balances, December 31, 2013

     10.0      $ 95,451        13,608,459      $ 21,488,387      $ (16,198,862   $ 5,384,976   

Redeemed common stock

         (1,200,000   $ (228,000     $ (228,000

Redeemed prefered stock

     (10.0     (95,451         17,951        (77,500

Net income

     —          —          —          —          325,907        325,907   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances, September 30, 2014

     —        $ —          12,408,459      $ 21,260,387      $ (15,855,004   $ 5,405,383   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

6


Table of Contents

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended September 30, 2013 and 2014

 

     2013     2014  

Cash Flows from Operating Activities:

    

Net income (loss)

   $ (16,119   $ 325,907   

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

    

Depreciation, depletion and amortization

     516,502        486,061   

Accretion of discount on asset retirement obligations

     50,034        49,712   

Gain on sale of oil and gas properties

     (28,449     (350,951

Common stock issued in exchage for services

     18,000        —     

Changes in operating assets and liabilities:

    

Accounts receivable

     (164,471     (208,639

Prepaid expenses and other

     30,166        (2,552

Accounts payable

     (71,389     83,069   

Directors fees and officers services payable

     —          19,200   

Accrued costs and expenses

     (138,558     12,781   
  

 

 

   

 

 

 

Net cash provided by operating activities

     195,716        414,588   
  

 

 

   

 

 

 

Cash Flows from Investing Activities:

    

Capital expenditures for property and equipment

     (274,467     (449,791

Proceeds from sale of oil and gas properties

     28,449        263,438   
  

 

 

   

 

 

 

Net cash (used in) investing activities

     (246,018     (186,353
  

 

 

   

 

 

 

Cash Flows from Financing Activities:

    

Proceeds from notes and advance payable

     1,041,920        622,638   

Principal payments on notes payable

     (549,274     (1,080,776

Payment of dividends on preferred stock

     (391,875     —     

Redemption of common stock

     —          (228,000

Redemption of preferred stock

     (50,000     (15,500
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     50,771        (701,638
  

 

 

   

 

 

 

Net decrease in cash and equivalents

     469        (473,403

Cash and equivalents, beginning of period

     6,921        476,323   
  

 

 

   

 

 

 

Cash and equivalents, end of period

   $ 7,390      $ 2,920   
  

 

 

   

 

 

 

Supplemental Disclosure of Cash Flow Information:

    

Cash paid for interest

   $ 84,581      $ 77,589   
  

 

 

   

 

 

 

Cash paid for income taxes

   $ —        $ —     
  

 

 

   

 

 

 

Supplemental Disclosure of Non-cash Investing and Financing Activities:

    
  

 

 

   

 

 

 

Conversion of Series A-1 Preferred Stock to Notes Payable

   $ 600,000      $ 62,000   
  

 

 

   

 

 

 

The Accompanying Notes are an Integral Part of These Financial Statements.

 

7


Table of Contents

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

1. Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Company owns 100% of Arete Energy, Inc. which is an inactive subsidiary which has no assets, liabilities or operations. Arête has operated a natural gas gathering system in Wyoming since 2006 and on July 29, 2011 the Company purchased oil & natural gas properties in Colorado, Montana, Kansas, and Wyoming.

The Company seeks to focus on acquiring interests in traditional oil and gas ventures, and seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. In addition, the Company’s strategy includes purchase and sale of acreage prospective for oil and natural gas and seeking to obtain cash flow from the sale and farm out of such prospects.

2. Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared by the Company. In the opinion of management, the accompanying unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial position as of December 31, 2013 and September 30, 2014, and the results of operations, changes in stockholders’ equity, and cash flows for the periods ended September 30, 2013 and 2014. Operating results for the interim periods presented are not necessarily indicative of the results that may be expected for a full year. The Company’s 2013 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2013 Annual Report on Form 10-K.

Use of Estimates

Preparation of the Company’s financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

The only component of comprehensive income that is applicable to the Company is net income (loss). Accordingly, a separate statement of comprehensive income (loss) is not included in these financial statements.

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of Arête and its inactive subsidiary, Arete Energy, Inc. All intercompany accounts and transactions have been eliminated in consolidation.

Earnings per share

Basic net income (loss) per share of common stock is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted net income (loss) attributable to common stockholders is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding and other dilutive securities. The only potentially dilutive securities for the diluted earnings per share calculations consist of Series 1 preferred stock that is

 

8


Table of Contents

convertible into common stock at an exchange price of $3.30 per common share. As of September 30, 2014, the convertible preferred stock had no aggregate liquidation preference and was convertible and had no outstanding shares. These shares were excluded from the earnings per share calculation because it was anti-dilutive to assume conversion at the beginning of the quarter, which would have eliminated preferred dividends from the earnings per share calculation.

New Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides guidance for revenue recognition. ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets and supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU also supersedes some cost guidance included in Subtopic 605-35, “Revenue Recognition- Construction-Type and Production-Type Contracts.” ASU 2014-09’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under today’s guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for the Company beginning January 1, 2017 and, at that time, the Company may adopt the new standard under the full retrospective approach or the modified retrospective approach. Early adoption is not permitted. The Company is currently evaluating the method and impact the adoption of ASU 2014-09 will have on the Company’s unaudited consolidated financial statements and disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption.

3. Oil and Gas Properties

In December 2013, we sold one of our producing properties, which resulted in gross proceeds of approximately $1,004,000. This property was sold to an unrelated purchaser and pursuant to our amended purchase agreement entered into in September 2013, we were required to pay the related party sellers approximately $554,000 of the proceeds due to their contingent interest and, as a result our net proceeds were $450,000. After deducting the net book value of the property of $163,000, plus the asset retirement obligation assumed by the unrelated purchaser of $31,000, we recognized a gain of approximately $318,000. The Company retained a 1.57% overriding royalty interest in this property. This sale comprised approximately 1.1% of the Company’s barrels of oil equivalent (“BOE”) of oil and gas reserve quantities, and approximately 2.2% of the Company’s discounted future net revenues prior to the sale. The Company determined that this sale did not qualify for discontinued operations reporting.

The Company has participated as a working interest owner in five horizontal wells that have been and are in the process of being drilled in Campbell County and Converse County, Wyoming in the Turner and Shannon zone. The following is a description of the wells:

 

  1) The Thielen #1-21 is in Section 21 Township 43N. This well has been drilled to a total depth of approximately 15,350 including the lateral. The Company will have an approximate 1.06% working interest.

 

  2) The Thielen #2-21 is in Section 21 Township 43N. This well has been drilled to a total depth of approximately 15,330 feet including the lateral. The Company will have an approximate 1.06% working interest.

 

  3) The Starlight Federal 28H is located in Section 7, Township 43N. This well has been drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest.

 

  4) The Starlight Federal 30H is located in Section 7, Township 43N. This well is scheduled to be drilled in the fourth of quarter of 2014 and is planned to be drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest

 

  5) The Wibaux Gold Federal 4076-10-03-1SH is located in Section 10, Township 40. This well is in the process of being drilled and is expected to be completed to be drilled to a total depth of approximately 20,185 including the lateral. The Company will have an approximate 0.3488% working interest.

 

9


Table of Contents

The Company has received the results on three of the wells and these results have been included in this filing. We do not have results on the other two wells other then the drilling is in process.

4. Income taxes

The book to tax temporary differences resulting in deferred tax assets and liabilities are primarily net operating loss carry forwards of approximately $7.6 million which expire in 2015 through 2032. A 100% valuation allowance has been established against the deferred tax assets, as utilization of the loss carry forwards and realization of other deferred tax assets cannot be reasonably assured. For the nine months ended September 30, 2014, the Company did not recognize any income tax benefit due to the valuation allowance.

5. Stock transactions and preferred stock dividends

During the quarter ended September 30, 2014, the Company did not issue any common stock for compensation or services.

The Company agreed to repurchase 10 shares of Preferred Stock. The following are the details of the transaction:

On August 15, 2014, the remaining preferred shareholder made an agreement with The Company to redeem his 10 shares of Series A-1 Convertible Preferred Stock. The Company paid $77,500 for the shares as follows; $15,500 in cash and a promissory note for $62,000.

The Company agreed to repurchase 1,200,000 shares of its Common Stock. The following are the details of the transaction:

On December 10, 2013, Burlingame Equity Investors Master Fund LP (“Burlingame”), a significant stockholder of Arête Industries, Inc. (the “Company”) entered into conditional stock option agreements with Nicholas L. Scheidt, the Company’s Chief Executive Officer and Director, pursuant to which Mr. Scheidt was granted options to purchase up to 1,460,000 shares of Company common stock at $0.19 per share. Mr. Scheidt subsequently assigned the right to purchase 1,200,000 shares to the Company on January 27, 2014. On January 30, 2014, the Company entered into a Direct Stock Purchase Agreement with Burlingame pursuant to which the Company has purchased the 1,200,000 shares of its common stock from Burlingame at a price of $0.19 per share for total consideration of $228,000. In addition, Mr. Scheidt assigned an additional 141,873 shares of Company common stock underlying his option from Burlingame to Donald W. Prosser, the Company’s Chief Financial Officer and Director. Pursuant to this assignment, Mr. Prosser agreed to purchase the entire 141,873 shares of Company common stock from Burlingame at a price of US $0.19 per share for total consideration of $26,956. Furthermore, of these 141,873 shares, Mr. Prosser agreed to transfer 57,895 shares to William W. Stewart, a Director of the Company, for $11,000 or $0.19 per share and 13,158 shares to Apex Financial Services Corp, a company controlled by Mr. Scheidt, for $2,500 or $0.19 per share. Finally, Mr. Scheidt agreed to exercise the remaining 118,127 shares of Company common stock under his option from Burlingame at a price of $0.19 per share for total consideration of $22,444.

6. Contracts Payable

The Company entered into a consulting contract for financing, structure, and investor services on March 2, 2010 for 800,000 shares of Common Stock valued at $500,000. The contract was for a period of three years and the fair value of the services were amortized ratably over the service period. Accordingly, the Company recognized a charge to investor relations expense of $27,778 and $0 for the nine months ended September 30, 2013 and 2014, respectively.

 

10


Table of Contents

7. Notes and advances payable

Notes payable consist of the following as of December 31, 2013 and September 30, 2014:

 

     2013      2014  

Officers, directors and affiliates:

     

Notes and advances payable, interest at 8.0%, due on demand

   $ 14,984       $ —     

Notes and advances payable, interest at 9.7%, due on demand

     85,000         —     

Note payable, interest at 7.0%, due March 2015

     150,000         150,000   

Notes payable, interest 7.0%, due January 2017

     —           128,019   

Notes payable, interest varies (see explanation below)

     —           792,151   

Collateralized note payable (see below)

     714,488         120,728   
  

 

 

    

 

 

 

Total officers, directors and affiliates

     964,472         1,190,898   

Less: Current portion of officers, directors, and affiliates

     717,833         296,033   
  

 

 

    

 

 

 

Long-term portion of officers, directors, and affiliates

   $ 246,639       $ 894,865   
  

 

 

    

 

 

 

Unrelated parties:

     

Notes payable, interest at 7.5%, due March 2015

     200,000         125,000   

Note payable, interest variable (see below)

     —           549,105   

Note payable, interest at 7.0%, due August 2016

     —           62,000   

Notes payable, interest at 7.0%, due January 2015

     44,000         —     

Notes payable, interest at 7.0%, due January 2015

     506,000         228,000   
  

 

 

    

 

 

 

Total unrelated parties

     750,000         964,105   

Less: Current portion of unrelated parties

     325,000         933,105   
  

 

 

    

 

 

 

Long-term portion of unrelated parties

   $ 425,000       $ 31,000   
  

 

 

    

 

 

 

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on December 31, 2014. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The outstanding principal balance as of September 30, 2014 was $120,728.

On January 28, 2014, we entered into a line of credit loan agreement for $1,500,000 due January 15, 2015. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.25%) plus an add on index with the current and minimum rate of 6.5%., the note has draw provisions, with the first draw of $479,701 4) the note is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Bank pledged by a related party, and 5) the personal guarantee of the Nicholas Scheidt, Chief Executive Officer. The amount eligible for borrowing on the Credit Facility is limited to the lesser of (i) 65% of the Company’s PV10 value of its carbon reserves based upon the most current engineering reserve report or (ii) 48 month cumulative cash flow based upon the most current engineering reserve report. In addition to the borrowing base limitation, the Company is required to maintain and meet certain affirmative and negative covenants and conditions in order to draw advances on the Credit Facility. The Credit Facility contains certain representations, warranties, and affirmative and negative covenants applicable to the Company, which are customarily applicable to senior secured loan facilities. Key covenants include limitations on indebtedness, restricted payments, creation of liens on oil and gas properties, hedging transactions, mergers and consolidations, sales of assets, use of loan proceeds, change in business, and change in control. The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 21% per annum. In addition, the Credit Facility contains customary events of default, including: (a) failure to pay any obligations

 

11


Table of Contents

when due; (b) failure to comply with certain restrictive covenants; (c) false or misleading representations or warranties; (d) defaults of other indebtedness; (e) specified events of bankruptcy, insolvency or similar proceedings; (f) one or more final, non-appealable judgments in excess of $50,000 that is not covered by insurance; (g) change in control (25% threshold); (h) negative events affecting the Guarantor; and (i) lender in good faith believes itself insecure. In an event of default arising from the specified events, the Credit Facility provides that the commitments thereunder will terminate and the Lender may take such other actions as permitted including, declaring any principal and accrued interest owed on the line of credit to become immediately due and payable. The Credit Facility is secured by a security interest in substantially all of the assets of the Company, pursuant to a Security Agreement, Deed of Trust and Assignment of As-Extracted Collateral entered into between the Company and Citywide Banks. The outstanding principal balance as of September 30, 2014 was $549,105.

On January 1, 2014, we memorialized our short-term liabilities into formal promissory notes. These certain outstanding advances and other notes payable are now included in single promissory notes, all have been reported previously in our financial statements. Information concerning these promissory notes is set forth in the table below.

 

Name of Holder

   Position    Principal
Amount
     Interest
Rate
    Monthly P&I
Payment
Amount
     Number
of
Monthly
Payments
 

Donald W. Prosser

   CFO & Director    $ 28,500         7.00   $ 564.33         60   

Charles B. Davis

   COO & Director    $ 66,500         7.00   $ 1,316.78         60   

William Stewart

   Director    $ 49,500         7.00   $ 980.16         36   

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum. The outstanding principal balances as of September 30, 2014 was $128,019.

In addition, we also issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR Oil & Gas, Inc. (“DNR”). DNR is a company controlled by one of our directors, Charles B. Davis. The DNR note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019. The DNR note requires payments as follows:

 

    One payment of $250,000 in 2016;

 

    One payment of $250,000 in 2017;

 

    One payment of $250,000 in 2018; and

 

    The balance of principal and accrued interest on or before January 1, 2019.

The DNR note contains customary default and acceleration provisions and provides for a default interest rate of 18% per annum. The outstanding principal balance as of September 30, 2014 was $792,151.

In June 2013, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company issued unsecured promissory notes in the original principal amounts of $48,000 and $552,000, respectively, with interest at 7% per annum payable quarterly and all unpaid interest and principal due on July 23, 2014. In connection with our new line of credit, we have agreed with the holders of these two existing notes to make a partial prepayment on the principal balance of the Notes in exchange for an extension of the maturity date to January 27, 2015. Information concerning the principal pay down and new maturity date is set forth in the following table.

 

Name of Holder

   Principal Balance
Before Pay down
     Principal
Pay down
     Remaining
Principal Balance
 

Burlingame Equity Investors II, LP

   $ 44,000       $ 36,000       $ 8,000   

Burlingame Equity Investors Master Fund, LP

   $ 506,000       $ 286,000       $ 220,000   

 

12


Table of Contents

On August 15, 2014 the Company executed a Promissory Note to an individual for the redemption of 10 shares of Series A-1 Preferred Stock. The terms of the Promissory Note are as follows: $62,000 with an interest rate of 7% payable in two payments of $31,000 each plus interest, due August 15, 2015 and August 15, 2016 respectively.

All of the notes payable shown above are unsecured, except the Apex note. Accrued interest on notes and advances payable amounted to $52,242 as of December 31, 2013 and $20,507 as of September 30, 2014.

8. Asset retirement obligations (ARO)

A reconciliation of the Company’s asset retirement obligations for the quarter ended September 30, 2014, is as follows:

 

Balance, December 31, 2013

   $ 682,203   

Liabilities incurred

     —     

Accretion expense

     49,712   

Payment on liability

     (36,250
  

 

 

 

Balance, September 30, 2014

     695,665   

Less current asset retirement obligations

     (154,398 )
  

 

 

 

Long-term asset retirement obligations

   $ 541,267   
  

 

 

 

9. Subsequent Events

The Company signed a contract with an Partnership owned by an Officer and Director to purchase an option to repurchase certain mineral interest currently held by a third party pursuant to a Purchase and Sales Agreement dated July 10, 2014 with that third party, in exchange for issuing 150,000 of its restricted common shares, on or before October 15, 2014 currently valued at $37,500. The Purchase and Sales Agreement states that the option price is $60,000 if it is exercised after December 1, 2014 and before December 31, 2014. The Company shall have the right, at its option, to put back the purchase from the partnership owned by the related party on or before February 1, 2016, the minerals, which are the subject matter of the Purchase and Sales Agreement described above, in the amount of $97,500 less any disbursement, royalties, or other revenues derived from the minerals during the period between December 1, 2014 and the Put date in the event that disbursement, royalties, and other revenues during the above described period are less than twelve percent (12%) annual return.

Consulting Agreement

Due to the recent need of additional assistance with respect to corporate matters and operational needs, on October 21, 2014, we entered into a Consulting Agreement with William W. Stewart, a Director of the Company to assist with the follow of documents, gathering information on the current properties to assist with further drilling and development, and help with information to speed up the compliance process.

The agreement is for a term of eight months. For his consulting services, we have agreed to pay Mr. Stewart a monthly cash retainer of $3,000 per month. In addition, the Company has agreed to issue Mr. Stewart 40,000 restricted shares (the “Restricted Shares”) of the Company’s common stock which are subject to vesting in increments of 5,000 per month.

The Company may terminate the agreement prior to the end of its term; however, if the agreement is terminated early without cause, the Company will be obligated to pay any remaining monthly cash payments. If Mr. Stewart terminates the agreement prior to the expiration of its term or the Company terminates it for cause, then Mr. Stewart will not be entitled to any further monthly payments. If Mr. Stewart’s service as a Director of the Company or consultant under the agreement cease during the term of the agreement, then he will forfeit the remainder of the unvested Restricted Shares. However, if there is a change of control (as defined in the agreement) in the Company, then any unvested Restricted Shares will immediately vest. A “change of control” includes a (i) tender offer which results in a greater than 50% change in the stock ownership of the Company, (ii) merger or consolidation with another company unless Company stockholders own more than 50% of the outstanding voting securities in the surviving or resulting corporation, and (iii) sale of substantially all of the Company’s assets to a third party.

 

13


Table of Contents

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

Forward-looking information

This report contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act of 1934, as amended, that are based on management’s exercise of business judgment as well as assumptions made by, and information currently available to, management. When used in this document, the words “may”, “will”, “anticipate”, “believe”, “estimate”, “expect”, “intend”, and words of similar import, are intended to identify any forward-looking statements. You should not place undue reliance on these forward-looking statements. These statements reflect our current view of future events and are subject to certain risks and uncertainties as noted below. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results could differ materially from those anticipated in these forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our expectations will materialize.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with our audited financial statements and related notes included in our Annual Report on Form 10-K and the financial statements and footnotes included in this Quarterly Report on Form 10-Q. This Quarterly Report on Form 10-Q, including the following discussion, contains trend analysis and other forward-looking statements within the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Any statements in this Quarterly Report on Form 10-Q that are not statements of historical facts are forward-looking statements. These forward-looking statements made herein are based on our current expectations, involve a number of risks and uncertainties and should not be considered as guarantees of future performance. The factors that could cause actual results to differ materially include without limitation:

 

    unsuccessful drilling and completion activities and the possibility of resulting write-downs;

 

    capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

 

    price volatility of oil and natural gas prices, and the effect that lower prices may have on our earnings and stockholders’ equity;

 

    a decline in oil or natural gas production or oil or natural gas prices, and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

 

    geographical concentration of our operations;

 

    increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

 

    our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities;

 

    failure to meet our proposed drilling schedule;

 

    adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through acquisition, exploration and development activities;

 

    our current level of indebtedness and the effect of any increase in our level of indebtedness;

 

    limited control over non-operated properties;

 

    reliance on limited number of customers;

 

    title defects to our properties and inability to retain our leases;

 

    our ability to retain key members of our senior management and key consulting resources;

 

    federal and state regulations and laws;

 

14


Table of Contents
    impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

 

    federal and state legislation and regulatory initiatives relating to hydraulic fracturing;

 

    risks in connection with evaluating potential acquisitions, integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;

 

    developments in the global economy;

 

    financing and interest rate exposure;

 

    effects of competition;

 

    effect of seasonal factors;

 

    lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and

 

    further sales or issuances of common stock.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

General Overview

It is our desire to provide an understanding of the Company’s past performance, its financial condition and its prospects for the future. Accordingly, we will discuss and provide our analysis of the following:

 

    Critical accounting policies;

 

    Results of operations;

 

    Liquidity and capital resources;

 

    Contractual obligations;

 

    Off-Balance sheet arrangements;

 

    New accounting pronouncements.

In the third quarter of 2011, we completed an acquisition of producing oil and natural gas properties in Montana, Wyoming, Colorado and Kansas. These properties include several proved undeveloped and probable drilling opportunities. While we have made progress to implement our business strategy over the past year, we believe our primary challenge over the next few months is to obtain additional financing to exploit existing drilling opportunities and to possibly acquire additional properties. We have sold some of our properties while retaining overriding royalty interests for future upside upon further development of the properties. In addition, we are in the process of reviewing opportunities for the purchase of production and undeveloped oil and gas leases for future development. However, in order to purchase properties or begin substantive drilling activities we must obtain additional financing, which cannot be assured. We rely heavily on the skills of our board members in the fields of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations.

 

15


Table of Contents

Critical Accounting Policies

The following discussion and analysis of the results of operations and financial condition are based on the our consolidated financial statements that have been prepared in accordance with accounting principles generally accepted in the United States of America. Our significant accounting policies are more fully described in Note 2 of the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended, December 31, 2013, as supplemented by the Unaudited Notes to Consolidated Financial Statements included herein. However, certain accounting policies and estimates are particularly important to the understanding of our financial position and results of operations and require the application of significant judgment by our management or can be materially affected by changes from period to period in economic factors or conditions that are outside of our control. As a result, they are subject to uncertainty. In applying these policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our future business plans and projected financial results, the terms of existing contracts, our observance of trends in the oil and gas industry, information provided by our customers and information available from other outside sources, as appropriate. Actual results may differ from these estimates. We believe the following critical accounting policies affect our most significant judgments and estimates used in the preparation of our consolidated financial statements.

Revenue Recognition

We record revenue from the sale of natural gas, natural gas liquids (“NGL”) and crude oil when delivery to the purchaser has occurred and title has transferred. We use the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by us. In addition, we will record revenue for our share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ gas sold by us that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved oil and gas reserves. Gas imbalances at September 30, 2014 were not material.

Property and equipment

In January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting “, which was also effective in 2010.

Our oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the consolidated statements of cash flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

 

16


Table of Contents

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

We review our proved oil and gas properties and our gas gathering system for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of assets evaluated for impairment and compare such undiscounted future cash flows to the carrying amount of the respective asset to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the asset to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel of oil equivalents (“BOE”) at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the consolidated balance sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the consolidated statements of operations.

Stock-based Compensation

We have not granted any stock options or warrants during the quarters ended September 30, 2013 and 2014, and no options or warrants were outstanding at any time during 2013 and 2014. We issued shares of common stock for services performed by officers, directors and unrelated parties during 2013 and we expect to issue shares for services in the future. We recorded these transactions based on the value of the services or the value of the common stock, whichever was more readily determinable.

Results of Operations for the Quarters Ended September 30, 2013 and 2014

To date, inflation has not had a material impact on our operations. Presented below is a discussion of our results of operations for the Quarters Ended September 30, 2013 and 2014.

 

17


Table of Contents

Oil and Gas Producing Activities

The results of our producing oil and gas properties in Wyoming, Colorado, Kansas and Montana are presented below is a summary of our oil and gas operations for the quarters ended September 30, 2013 and 2014:

 

     2013     2014  

Oil Sales

   $ 550,330      $ 484,386   

Natural Gas Sales

     113,876        71,598   

Royalty Revenue

     553        755   

Sale of Oil & Natural Gas Properties

     27,500        108,479   
  

 

 

   

 

 

 

Total Revenue

     692,259        688,618   

Production Taxes

     (58,586     (52,245

Lease Operating Expense

     (187,126     (196,134

Depreciation, depletion, amortization and accretion

     (209,611     (210,335
  

 

 

   

 

 

 

Net

   $ 236,936      $ 229,904   
  

 

 

   

 

 

 

Net barrels of oil sold

     5,736        5,960   

Net mcf of gas sold

     21,853        14,627   

Average price for oil

   $ 95.95      $ 81.27   
  

 

 

   

 

 

 

Average price for gas

   $ 5.21      $ 4.89   
  

 

 

   

 

 

 

Lease operating expense per BOE

   $ 19.95      $ 23.35   
  

 

 

   

 

 

 

DD&A per BOE

   $ 22.35      $ 25.05   
  

 

 

   

 

 

 

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the second quarter of 2013 was $95.95 per barrel but ranged from a low of $93.72 for September and a high of $98.72 for August. The average oil price for the third quarter of 2014 was $81.35 per barrel but ranged from a low of $73.95 for August to a high of $89.93 for July. The average natural gas prices, including proceeds from sales of natural gas liquids, amounted to $5.21 per Mcf for the third quarter of 2013. Our average natural gas prices, including proceeds from sales of natural gas liquids, amounted to $4.89 per Mcf for the third quarter of 2014.

Production taxes were approximately 8% of our oil and gas sales for the third quarters of 2013 and 2014. Lease operating expense averaged $19.95 per Barrel of Oil Equivalent (“BOE”), whereby six Mcf of gas are equal to one barrel of oil, for the third quarter of 2013. Lease operating expense averaged $23.35 per Barrel of Oil Equivalent (“BOE”) for the same period 2014. Many of the wells included in our acquisition have been producing for a decade or longer and the cost of workovers and normal maintenance are charged to expense in the period the costs are incurred. For the third quarter of 2013, we incurred approximately $85,400 for workovers, well service units and repairs which accounted for approximately $9.11 per BOE of our lease operating expenses that was capitalized based on increased production the wells. For the third quarter of 2014, we incurred approximately $58,000 for workovers, well service units and repairs which accounted for approximately $5.99 per BOE that were capitalized.

Under successful efforts accounting, DD&A expense is separately computed for each producing field based on geologic and reservoir delineation. The capital expenditures for proved properties for each field

 

18


Table of Contents

compared to the proved reserves corresponding to each producing field determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

During the third quarter 2014 we sold our share of the five new wells in which we participated as a small working interest owner for a promote fee of $108,479 and we are still participating in a part of each of the well. We expect to periodically evaluate our portfolio of properties and sell additional properties if we believe a sale can be completed on terms that provide attractive returns.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. We had no revenues for the third quarters of 2013 and 2014, due to low natural gas prices which resulted in all wells in the field being shut-in since June 2011.

Presented below is a summary of operating costs for the quarters ended September 30, 2013 and 2014:

 

     2013      2014  

Related party- cost of production

   $ —         $ —     
  

 

 

    

 

 

 

Unrelated parties:

     

Compressor rental

     —           —     

Pumper costs

     —           —     

Transportation

     —           —     

Property taxes

     1,275         609   

Land rent, utilities, repairs and other

     2,268         —     
  

 

 

    

 

 

 

Total unrelated party costs

     3,543         609   
  

 

 

    

 

 

 

Total

   $ 3,543       $ 609   
  

 

 

    

 

 

 

Depreciation expense related to the gas gathering system was $11,055 for the third quarter of both 2013 and 2014.

In July 2011, we acquired the entire field of coal bed methane wells as part of our $11 million acquisition. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest substantial gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. We expect to further evaluate these properties and, if warranted, execute our development plans within the next three years in seeking to exploit the value of the properties and the gas gathering system. As of September 30, 2014, the capitalized cost of the coal bed methane leases is $248,295 and the net capitalized cost of the gas gathering system is $111,922.

 

19


Table of Contents

General and Administrative

Presented below is a summary of general and administrative expenses for the quarters ended September 30, 2013 and 2014:

 

     2013      2014      Change  

Director fees

   $ 450       $ 10,000       $ 9,550   

Investor relations

     10,922         2,448         (8,474

Legal, auditing and transfer agent

     21,580         37,109         15,529   

Accounting, financial reporting and rent- related party

     750         —           (750

Consulting fees:

        

Related parties

     30,000         41,250         11,250   

Unrelated parties

     —           —           —     

Other administrative expense

     3,653         18,084         14,431   

Depreciation

     142         143         1   
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

   $ 67,497       $ 109,034       $ 41,537   
  

 

 

    

 

 

    

 

 

 

General and administrative expenses increased by $41,537 in 2014 compared to 2013. The management has provided accounting services and all needed administrative services for compliance with regulatory agencies and no cost to the Company.

The monthly charge of $10,000 under an agreement with DNR, whereby executive level expertise is provided for our existing and prospective oil and properties. The total monthly charge under the operating agreement is $18,000, of which $8,000 is allocated to lease operating expense. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

The Company in the second quarter of 2014 the board of directors voted to pay Nicholas Scheidt $90,000 for consulting and management of the Company through December 31, 2014. The Company accrued $11,250 during the three months ended September 30, 2014.

Income from operations

Income from operations for the third quarter of 2014 was $85,806 compared to a income of $154,841 for the third quarter of 2013. The decrease in income of $69,035 was primarily due to the increase in the gain on sale of oil and gas properties less the items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and administrative expenses.

Interest Expense

Interest expense decreased by $3,343 in the third quarter of 2014 to $33,350 from $36,693 in the third quarter of 2013.

 

20


Table of Contents

Results of Operations for the Nine-Months Ended September 30, 2013 and 2014

To date, inflation has not had a material impact on our operations. Presented below is a discussion of our results of operations for the nine-months ended September 30, 2013 and 2014.

Oil and Gas Producing Activities

Presented below is a summary of our oil and gas operations for the nine months ended September 30, 2013 and 2014:

 

     2013     2014  

Oil Sales

   $ 1,308,228      $ 1,433,994   

Natural Gas Sales

     329,990        287,229   

Royalty Revenue

     533        2,525   

Sale of Oil & Natural Gas Properties

     28,449        350,951   
  

 

 

   

 

 

 

Total Revenue

     1,667,200        2,074,699   

Production Taxes

     (135,451     (143,891

Lease Operating Expense

     (528,526     (566,068

Depreciation, depletion, amortization and accretion

     (532,946     (502,180
  

 

 

   

 

 

 

Net

   $ 470,277      $ 862,560   
  

 

 

   

 

 

 

Net barrels of oil sold

     15,116        16,727   

Net mcf of gas sold

     64,258        50,859   

Average price for oil

   $ 86.55      $ 85.73   
  

 

 

   

 

 

 

Average price for gas

   $ 5.13      $ 5.65   
  

 

 

   

 

 

 

Lease operating expense per BOE

   $ 20.46      $ 22.17   
  

 

 

   

 

 

 

DD&A per BOE

   $ 20.64      $ 19.66   
  

 

 

   

 

 

 

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average oil price for the nine months ended September 30, 2013 was $86.55 per barrel but ranged from a low of $78.10 for March and a high of $92.76 for June. The average oil price for the nine months ended September 30, 2014 was $85.73 per barrel but ranged from a low of $72.68 for January to a high of $95.36 for May. The average natural gas prices, including proceeds from sales of natural gas liquids, amounted to $5.13 per Mcf for the nine months ended September 30, 2013. Our average natural gas prices, including proceeds from sales of natural gas liquids, amounted to $5.65 per Mcf for the nine months ended September 30, 2014.

Production taxes were approximately 8% of our oil and gas sales for the nine months ended September 30, 2013 and 2014. Lease operating expense averaged $20.46 per Barrel of Oil Equivalent (“BOE”), whereby six Mcf of gas are equal to one barrel of oil, for the nine months ended September 30, 2013. Lease operating expense averaged $22.17 per Barrel of Oil Equivalent (“BOE”) for the same period 2014. Many of the wells included in our acquisition have been producing for a decade or longer and the cost of workovers and normal maintenance are charged to expense in the period the costs are incurred. For the nine months ended September 30, 2013, we incurred approximately $164,400 for workovers, well service units and repairs which accounted for approximately $6.37 per BOE of our lease operating expenses that was capitalized based on increased production the wells. For the nine months ended September 30, 2014, we incurred approximately $182,000 for workovers, well service units and repairs which accounted for approximately $7.12 per BOE that were capitalized.

 

21


Table of Contents

Under successful efforts accounting, DD&A expense is separately computed for each producing field based on geologic and reservoir delineation. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

During the nine months ended September 30, 2014 we sold our share of the five new wells in which we participated as a small working interest owner for a promote fee of $350,951 and we are still participating in a part of each of the well. We expect to periodically evaluate our portfolio of properties and sell additional properties if we believe a sale can be completed on terms that provide attractive returns.

Gas Gathering Activities

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. We had no revenues for the nine months ended September 30, 2013 and 2014, due to low natural gas prices which resulted in all wells in the field being shut-in since June 2011.

Presented below is a summary of operating costs for the nine months ended September 30, 2013 and 2014:

 

     2013      2014  

Related party- cost of production

   $ —         $ —     
  

 

 

    

 

 

 

Unrelated parties:

     

Compressor rental

     —           —     

Pumper costs

     —           —     

Transportation

     —           —     

Property taxes

     3,825         2,844   

Land rent, utilities, repairs and other

     7,403         5,135   
  

 

 

    

 

 

 

Total unrelated party costs

     11,228         7,979   
  

 

 

    

 

 

 

Total

   $ 11,228       $ 7,979   
  

 

 

    

 

 

 

Depreciation expense related to the gas gathering system was $33,165 for the nine months ended September 30, 2013 and 2014.

In July 2011, we acquired the entire field of coal bed methane wells as part of our $11 million acquisition. While these wells are not economic at current prices being received for natural gas related to the production capability from the existing geologic formation, we have geologic and engineering data that suggest substantial gas reserves exist on these properties by drilling new wells and/or recompleting the existing wells to several new geologic formations. We expect to further evaluate these properties and, if warranted, execute our development plans within the next three years is seeking to exploit the value of the properties and the gas gathering system. As of September 30, 2014, the capitalized cost of the coal bed methane leases is $248,295 and the net capitalized cost of the gas gathering system is $111,922.

 

22


Table of Contents

General and Administrative

Presented below is a summary of general and administrative expenses for the nine months ended September 30, 2013 and 2014:

 

     2013      2014      Change  

Director fees

   $ 1,800       $ 10, 450       $ 8,650   

Investor relations

     86,349         37,634         (48,715

Legal, auditing and transfer agent

     118,470         115,753         (2,717

Accounting, financial reporting and rent- related party

     2,250         —           (2,250

Consulting fees:

        

Related parties

     90,000         168,750         78,750   

Unrelated parties

     —           —           —     

Other administrative expense

     44,215         59,166         14,951   

Depreciation

     427         428         1   
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

   $ 343,511       $ 392,181       $ 48,670   
  

 

 

    

 

 

    

 

 

 

General and administrative expenses increased by $48,670 in 2014 compared to 2013. The management has provided accounting services and all needed administrative services for compliance with regulatory agencies and no cost to the Company.

We incur a monthly charge of $10,000 under an agreement with DNR, whereby executive level expertise is provided for our existing and prospective oil and properties. The total monthly charge under the operating agreement is $18,000, of which $8,000 is allocated to lease operating expense. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

The Company in the second quarter of 2014 the board of directors voted to pay Nicholas Scheidt $90,000 for consulting and management of the Company through December 31, 2014. The Company accrued $78,750 during the nine months ended September 30, 2014.

Income from operations

Income from operations for the nine months ended September 30, 2014 was $429,235 compared to an income of $82,373 for the nine months ended September 30, 2013. The increase in income was primarily due to the gain on sale of oil and gas properties of $350,951, as well as the items discussed above relating to the oil and natural gas operations, gas gathering activities, and general and administrative expenses.

Interest Expense

Interest expense increased by $4,835 for the nine months ended September 30, 2014 to $103,328 from $98,493 for the nine months ended September, 2013 due to increase in borrowing and restructure of debt.

Liquidity and Capital Resources

We had a working capital deficit as of September 30, 2014 of $1,118,061, compared to a working capital deficit of $619,426 at December 31, 2013. The approximate $500,000 increase in our working capital deficit resulted from a decrease in cash from redeeming common stocks capital expenditures, an increase in current liabilities after restructure the Company’s debt, reduced by operating profits.

 

23


Table of Contents

We generated positive operating cash flow of $414,588 for the nine months ended September 30, 2014 compared to operating cash flow of $195,716 for the nine months ended September 30, 2013.

For the nine months ended September 30, 2014, we (used) $(186,353) of cash flows related to investing activities for capital expenditures. For the nine months ended September 30, 2013, we (used) $(246,018) of cash flows related to investing activities for capital expenditures.

For the nine months ended September 30, 2013, financing activities provided net cash flow of $50,771. For the nine months ended September 30, 2014, we had net cash financing activities that (used) $(701,638) as we borrowed $622,638, repaid borrowings of $1,080,776, redeemed common stock for $228,000, and redeemed series A-1preferred stock $15,500.

Part of our strategy is to monitor the current production of our properties, seek to develop them with infield drilling, and explore sales and purchases of additional leases and operating wells with upside. We are currently evaluating several opportunities for drilling in Wyoming and Colorado. As part of our evaluation we have entered into participating agreements for five wells in Wyoming. The Company has participated as a working interest owner in five horizontal wells. Three have been completed and two are in the process of being completed in Campbell County and Converse County, Wyoming in the Turner and Shannon zone. The following is a description of the wells:

 

  1) The Thielen #1-21 is in Section 21 Township 43N. This well has been drilled to a total depth of approximately 15,350 including the lateral. The Company will have an approximate 1.06% working interest.

 

  2) The Thielen #2-21 is in Section 21 Township 43N. This well has been drilled to a total depth of approximately 15,330 feet including the lateral. The Company will have an approximate 1.06% working interest.

 

  3) The Starlight Federal 28H is located in Section 7, Township 43N. This well has been drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest.

 

  4) The Starlight Federal 30H is located in Section 7, Township 43N. This well is scheduled to be drilled in the fourth of quarter of 2014 and is planned to be drilled to a total depth of approximately 15,310 including the lateral. The Company will have an approximate 0.7025% working interest

 

  5) The Wibaux Gold Federal 4076-10-03-1SH is located in Section 10, Township 40. This well is in the process of being drilled and is expected to be completed to be drilled to a total depth of approximately 20,185 including the lateral. The Company will have an approximate 0.3488% working interest.

The Company has received the results on three of the wells and these results have been included in this filing. We do not have results on the other two wells other then the drilling is in process.

As of September 30, 2014, we had cash and equivalents of approximately $3,000 and approximately $460,000 in receivables due from oil and natural gas operations in the next 60 days. We have a working capital loan for $1,500,000 and we have borrowed $550,000 and have a $950,000 available to use for growth. We also expect to evaluate acquisitions that are consistent with our business objective of acquiring interests in traditional oil and gas ventures, and seeking properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas.

 

24


Table of Contents

In order to execute our plan to acquire additional interests in oil and gas properties that meet our objectives, we need additional financing in addition to our working capital loan above. From the time we acquired our existing properties in the third quarter of 2011, we have sold our interests in some of those properties, which resulted in aggregate net proceeds from three sales of $6,377,000, which was used to repay acquisition indebtedness. We intend to only sell properties that can be liquidated for an attractive premium and there can be no assurance that we will continue to generate any proceeds from the sale of our properties.

If oil and gas prices decrease materially from current levels and additional debt or equity funding is unavailable on acceptable terms, or at all, our strategy would include some or all of the following: (i) defer development drilling on our existing properties, (ii) forego additional oil and gas property acquisitions, (iii) shut-in any marginal or uneconomic wells, (iv) attempt to negotiate the issuance of common stock in exchange for services, and (v) review and implement other opportunities to reduce general, administrative and operating expenses.

Contractual Obligations and Commercial Commitments

As of September 30, 2014, we have future minimum lease payments of approximately $6,000. This amount is payable during the years ending June 30, 2015, 2016, 2017, 2018 and after 2019 in the amounts of $1,000 each year respectively.

Off-Balance Sheet Arrangements

In connection with the related party acquisition of oil and gas properties in the third quarter of 2011, we acquired interests in certain geologic zones of the properties. The Colorado and Kansas properties provide for additional consideration that is payable to the related party sellers if proved producing reserves are increased relating to these properties through drilling or recompletion activities over a period of ten years after the closing date. First to the extent that oil reserves increase, the sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels. Second, to the extent that oil and gas prices increase, the sellers are entitled to additional consideration as the targeted price thresholds are exceeded for periods of 61 days. The increase in purchase price for the Kansas and Colorado properties is limited to a maximum of $5 million.

The acquired properties that are located in Wyoming and Montana provide a similar formula as used for the Colorado and Kansas properties that could result in an obligation for additional purchase consideration to the extent that we perform future drilling or recompletion activities in formations that were not producing as of the September 29, 2011 closing date. Furthermore, if we sell properties where reserves have been proved up through drilling or recompletion, the sellers have retained an interest of 70% in the net sales proceeds (after we receive a recovery of 125% of the original purchase allocation in the amended and restated purchase agreement). The increase in purchase price for all properties (Colorado, Kansas, Wyoming and Montana) is limited to a maximum of $25 million.

Due to consideration retained by the related party sellers from sales of properties through the first quarter of 2012, and $250,000 of consideration payable in December 2012 due to a sustained increase in oil prices over $100 per barrel, and the sale of a third property in December the maximum future consideration has been reduced by approximately $5.8 million to $19.2 million as of September 30, 2014.

SEC Formal Investigation

The Denver Regional Office of the Securities and Exchange Commission is conducting a non-public, formal, investigation (“SEC Investigation”) to determine whether there have been violations of certain provisions of the federal securities laws relating to the Company, its management and third parties. The principal areas of the SEC Investigation relate to the sale of certain Company securities, possible trading manipulation activities with respect to the Company’s common stock, and potential violations of the federal broker-dealer registration laws

 

25


Table of Contents

by persons or entities in connection with the purchase or sale of the Company’s securities. To date, neither the Company nor any of its directors, officers, or employees have been accused of any wrongdoing by the SEC. We also have been informed by the SEC that the existence of this investigation does not mean that the SEC has concluded that anyone has violated the law or that the SEC has a negative opinion of any person, entity, or security. We have been cooperating fully with the SEC. We cannot reasonably estimate the timing of the SEC Investigation, nor can we predict whether or not it might have a material adverse effect on our business.

New Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides guidance for revenue recognition. ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets and supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU also supersedes some cost guidance included in Subtopic 605-35, “Revenue Recognition- Construction-Type and Production-Type Contracts.” ASU 2014-09’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under today’s guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for the Company beginning January 1, 2017 and, at that time, the Company may adopt the new standard under the full retrospective approach or the modified retrospective approach. Early adoption is not permitted. The Company is currently evaluating the method and impact the adoption of ASU 2014-09 will have on the Company’s unaudited consolidated financial statements and disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

Item 3 - Quantitative and Qualitative Disclosures about Market Risk

The Company is a “Smaller Reporting Company” as defined by Rule 229.10 (f)(1) and is not required to provide or disclose the information required by this item.

Item 4 - Controls and Procedures

As of September 30, 2014, our Chief Executive Officer and Chief Financial Officer (the “Certifying Officers”) conducted evaluations of our disclosure controls and procedures. As defined under Sections 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including the Certifying Officers, to allow timely decisions regarding required disclosure. Based on this evaluation, the Certifying Officers have concluded that our disclosure controls and procedures were not effective to ensure that material information is recorded, processed, summarized and reported by our management on a timely basis in order to comply with our disclosure obligations under the Exchange Act and the rules and regulations promulgated thereunder. As discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, the ineffectiveness of our disclosure controls and procedures is due primarily to (i) our Board of Directors does not currently have any independent members that qualify as an audit committee financial expert, (ii) we have not developed and effectively communicated our accounting policies and procedures, and (iii) our controls over financial statement disclosures were determined to be ineffective.

Further, there were no changes in our internal control over financial reporting during the second fiscal quarter that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

26


Table of Contents

PART II - OTHER INFORMATION

Item 1 - Legal Proceedings.

From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its business. The Company is not aware of any material current, pending, or threatened litigation.

Item 1A - Risk Factors.

There have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on April 14, 2014. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2013, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

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

None

Item 3 - Defaults upon Senior Securities.

None

Item 4 - Mine Safety Disclosures.

Not Applicable

Item 5 - Other Information.

None

Item 6 - Exhibits

The following documents are filed as exhibits to this report on Form 10-Q or incorporated by reference herein.

 

31.1 Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

 

31.2 Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.

 

32.1 Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350.

 

32.2 Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

 

101 The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing.

 

27


Table of Contents

ARÊTE INDUSTRIES, INC.

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 thereunto duly authorized.

 

By:  

/s/ Nicholas Scheidt, CEO

  Nicholas L Scheidt, Principal Executive Officer
Dated:   November 20, 2014
By:  

/s/ Donald W. Prosser, CFO

  Donald W. Prosser, Principal Financial and Accounting Officer
Dated:   November 20, 2014

 

28