Exhibit 99.1

INDEPENDENT AUDITOR’S REPORT

Board of Directors

Arête Industries, Inc.

Westminster, Colorado

We have audited the accompanying statements of operating revenues and direct operating expenses (the “Statements”) of the oil and gas working interests acquired by Arête Industries, Inc. for the years ended December 31, 2009 and 2010. The Statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Statements based on our audits.

We conducted our audits in accordance with Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying Statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 2 and are not intended to be a complete presentation of the Properties’ revenues and expenses.

In our opinion, the Statements referred to above present fairly, in all material respects, the operating revenues and direct operating expenses of the oil and gas working interests acquired by Arête Industries, Inc. for the years ended December 31, 2009 and 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Causey Demgen & Moore P.C.

Denver, Colorado

October 12, 2012

 

 

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STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES

OF OIL & GAS WORKING INTERESTS ACQUIRED BY ARÊTE INDUSTRIES, INC.

(EXCLUDING THE “SEPARATE INTERESTS” DESCRIBED IN NOTE 1)

 

     Year Ended December 31:      Six Months Ended June 30:  
     2009      2010      2010      2011  
                   (Unaudited)      (Unaudited)  

Operating Revenues:

           

Oil sales

   $ 1,364,161       $ 1,568,153       $ 744,017       $ 1,206,498   

Natural gas sales

     402,445         518,785         271,884         290,817   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating revenues

     1,766,606         2,086,938         1,015,901         1,497,315   
  

 

 

    

 

 

    

 

 

    

 

 

 

Direct Operating Expenses

           

Lease operating expense

     1,147,813         1,172,340         566,240         560,649   

Production taxes

     153,703         167,742         80,380         121,183   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total direct operating expenses

     1,301,516         1,340,082         646,620         681,832   
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Revenues in Excess Of Direct Operating Expenses

   $ 465,090       $ 746,856       $ 369,281       $ 815,483   
  

 

 

    

 

 

    

 

 

    

 

 

 

The Accompanying Notes are an Integral Part of These Statements of Operating Revenues and Direct Operating Expenses.

 

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NOTES TO STATEMENTS OF OPERATING REVENUES

AND DIRECT OPERATING EXPENSES

 

1. SUMMARY OF ACQUISITION AGREEMENT:

On May 25, 2011, Arête Industries, Inc. (the “Company”) entered into a Purchase and Sale Agreement and other related agreements and documents with the Tucker Family Investments, LLLP, DNR Oil & Gas, Inc. (“DNR”), and Tindall Operating Company (collectively, the “Sellers”) for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana (collectively, the “Original Purchase and Sale Agreement”). DNR is principally owned by a director of the Company, Charles B. Davis. The consideration for the purchase was determined by bargaining between management of the Company and Sellers, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price for the properties was $10.0 million, of which the Company paid a nonrefundable down payment of $0.5 million and the remaining $9.5 million was financed by the Sellers pursuant to a promissory note due July 1, 2011. The Company was unable to arrange the funding to pay the $9.5 million promissory note due on July 1, 2011, and therefore, the note was not paid.

On July 29, 2011, the Company and Sellers entered into an Amended and Restated Purchase and Sale Agreement (“PSA”) regarding the purchase of (i) working interests in oil and gas properties located in Wyoming, Colorado, Kansas and Montana (referred to as the “Properties”), and (ii) vested contractual rights in the net proceeds from the future sale of certain properties located in Wyoming (referred to as the “Separate Interests”). The material terms of the PSA included an aggregate base purchase price for the Properties and the Separate Interests of $11.0 million to be paid by an initial payment of $0.9 million, comprised of (i) a credit in the amount of $0.5 million previously paid by the Company in connection with the Original Purchase and Sale Agreement; and (ii) $0.4 million in funds paid contemporaneously with the execution of the PSA. The remaining principal balance of the base purchase price in the amount of $10.1 million, together with interest at 10% per annum, was payable to Sellers in three monthly payments, with $3.7 million due August 15, 2011 (extended to August 31, 2011), and $3.2 million due on each of September 15, 2011 and October 15, 2011. By September 29, 2011, all required consideration had been paid to Sellers and closing was completed.

The PSA provided that the Company was entitled to proceeds from the production of oil and gas beginning on April 1, 2011, and the Company was also responsible for the lease operating expenses beginning on April 1, 2011. The net proceeds from oil and gas sales, less production taxes and lease operating expenses from April 1, 2011 to July 29, 2011 amounted to $628,260 for the Properties and $138,468 for the Separate Interests for an aggregate of $766,728. These amounts were treated as a reduction of the carrying costs of the Properties and the Separate Interests.

 

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The acquisition of the Properties was structured whereby the Company acquired 100% of Seller’s interest in certain geologic zones of the properties. Presented below is a summary of agreed-upon values associated with the Properties and the Separate Interests, along with a discussion of the interests in the Properties retained by the Sellers:

 

Properties:

  

Rex Lake/ Big Hollow (WY)

   $ 511,025 (b) 

Kansas

     2,152,216 (a) 

Montana

     98,179 (b) 

Wyoming

     2,733,773 (b) 

Buff (WY)

     611,211 (b) 

Colorado

     2,507,678 (a) 
  

 

 

 

Total Working Interest Properties

     8,6142,082   

Separate Interests

     2,385,918 (d) 
  

 

 

 
   $ 11,000,000 (c) 
  

 

 

 

 

(a) For a period of ten years after the closing date, the Colorado and Kansas properties provide for additional consideration that is payable to Sellers based on increases in Nymex prices for oil and natural gas, without regard to changes in the Company’s oil and natural gas reserves (referred to as the “Price Increase Factor”). If Nymex thresholds of $90, $100, $110, $125 and $150 per barrel of oil are exceeded for periods of 61 days or more, incremental purchase consideration of $250,000, $250,000, $500,000, $500,000 and $2,000,000, respectively, will be payable to Sellers. Similarly, if Nymex thresholds of $5.00, $6.00, $7.50, $10.00 and $12.00 per MMbtu of natural gas are exceeded for periods of 61 days or more, incremental purchase consideration of $50,000, $50,000, $150,000, $250,000 and $250,000, respectively, will be payable to Sellers.

The Colorado and Kansas properties also provide for additional consideration that is payable to Sellers if reserves classified as “possible” are converted to “proved producing reserves” through drilling or recompletion activities over a period of ten years after the closing date (referred to as the “Possible Reserve Factor”). For such increases in oil reserves, the Sellers are entitled to additional consideration of $250,000 for each increase of 20,000 net barrels; and for such increases in natural gas reserves, the Sellers are entitled to additional consideration of $150,000 for each increase of 150,000 mcf of natural gas.

The Possible Reserve Factor also requires a multiplier effect from 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained. For example, the Possible Reserve Factor consideration would be multiplied by 2 if the oil Price Increase Factor of $100 is in effect when the proved producing reserves are confirmed. Similarly, the Possible Reserve Factor consideration would be multiplied by 2 if a natural gas Price Increase Factor of $6.00 per MMbtu is in effect when the proved producing natural gas reserves are confirmed.

The maximum increase in purchase price for the Kansas and Colorado properties is limited to $5 million.

 

(b) Additional consideration is also payable for the properties located in Wyoming to the extent that the Company increases proved producing reserves through future drilling or recompletion activities in formations that are not producing as of the closing date under the Possible Reserve Factor. Similar to the properties in Colorado and Kansas, the Possible Reserve Factor will be multiplied by a factor of 1 to 5 depending on the Price Increase Factor that is effective when the proved producing reserves are obtained.

 

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Furthermore, if the Company sells any of the properties in Wyoming, the Sellers have retained an interest of 70% in the net sales proceeds (after the Company receives a recovery of 125% of the original agreed-upon allocation as contained in the table above).

The maximum increase in purchase price (including Sellers retained interest of 70% for the Wyoming properties discussed in the preceding paragraph) for all properties in all states shown in the table above is limited to $25 million. Due to the sale of the Separate Interests discussed below, accrual of $250,000 due to a sustained increase in oil prices over $90 per barrel recorded during the fourth quarter of 2011, and the sale of a second property in February 2012, the maximum future consideration has been reduced by approximately $5.0 million to $20.0 million.

 

(c) Note that the values shown in this table are the allocation amounts attributable to the proved developed zones agreed to between the Company and the Sellers, before purchase adjustments for pre-acquisition net revenues received, oil in tanks and contingent purchase price adjustments. These adjustments do not modify the agreed upon value for purposes of the adjustments discussed above but will affect the final purchase allocation under generally accepted accounting principles.

 

(d) Prior to the complete payment for the Properties and formal closing on September 29, 2011, the Separate Interests were sold on August 23, 2011. The Company acquired the contractual rights associated with the Separate Interests on July 29, 2011, and the Company’s share of the net proceeds of $5,101,000 was received on August 23, 2011; the result was the recognition of a gain in the third quarter of 2011 of approximately $2,480,000. The Company applied the $5,101,000 of net proceeds to the payments due under the PSA.

 

2. BASIS OF PRESENTATION:

The accompanying statements of operating revenues and direct operating expenses (the “Statements”) of the working interests in Oil and Gas Properties (“Properties”) acquired by the Company were prepared by the Sellers based on carved out financial information and data from the Properties’ historical accounting records. The Statements exclude the operating revenues and direct operating expenses of the Separate Interests described in Note 1. Historical financial statements prepared in accordance with generally accepted accounting principles have never been prepared for the Properties. The oil and gas wells that comprise the Properties were owned by between five and seventeen different owners and in most cases the original drilling and development activities took place up to thirty years prior to the Company’s acquisition.

Because the Properties are not separate legal entities, 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 expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses, interest expense, and other expenses. These costs were not separately allocated to the Properties in the accounting records of Sellers. In addition, these allocations, if made using historical general and administrative structures and tax burdens, may not produce allocations that would be indicative of the historical performance of the Properties had they been the Company’s properties due to the differing size, structure, operations and accounting policies of the Sellers and the Company.

 

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The accompanying Statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs which the Company will incur upon the allocation of the purchase price paid for the Properties. Furthermore, no balance sheet has been presented for the Properties, because not all of the historical cost and related working capital balances are segregated or easily obtainable, nor has information about the Properties operating, investing and financing cash flows been provided for similar reasons. Accordingly, the accompanying Statements are presented in lieu of the financial statements required under Rule 8-04 of Securities and Exchange Commission Regulation S-X.

 

3. USE OF ESTIMATES IN PREPARATION OF FINANCIAL STATEMENTS:

The preparation of the Statements of Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of operating revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of the Statements of Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company.

 

4. CRITICAL ACCOUNTING POLICIES:

The Sellers record revenue from the sale of crude oil and natural gas in the month that delivery to the purchaser occurs and title has transferred. The impact of gas imbalances is not material.

Direct Operating Expenses include overhead charges, contract pumper services, salt water disposal, utilities, repairs, maintenance, and other direct costs. All Direct Operating Expenses, including the cost of workovers and repairs to well equipment, are charged to expense in the period incurred. For the years ended December 31, 2009 and 2010, the Sellers did not drill any wells on the properties acquired by the Company and, accordingly, all costs incurred to operate the wells have been included in lease operating expense.

 

5. COMMITMENTS AND CONTINGENCIES:

Pursuant to the terms of the purchase and sale agreement, there are no known claims, litigation or disputes pending as of the effective date of the PSA, or any matters arising in connection with indemnification, and the parties to the agreement are not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the Operating Revenues and Direct Operating Expenses of the Properties acquired by the Company.

 

6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited):

The reserve information presented below is based on estimates of net proved reserves of the Properties as of December 31, 2009 and 2010 that were prepared by the Company’s independent petroleum engineering firm, in accordance with guidelines established by the SEC. This reserve information excludes the Separate Interests described in Note 1(d).

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that

 

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can be expected to be recovered through existing wells with existing equipment and operating methods. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Properties’ proved reserves are located in the continental United States.

The following table sets forth information for the years ended December 31, 2009 and 2010 with respect to changes in the Properties’ proved developed and proved undeveloped reserves:

 

     Crude Oil
(Bbl)
    Natural Gas
(Mcf)
 

Proved Reserves, December 31, 2008

     310,267        678,564   

Production during 2009

     (23,995     (174,724
  

 

 

   

 

 

 

Proved Reserves, December 31, 2009

     286,272        503,840   

Revisions of previous estimates

     119,176        274,864   

Production during 2010

     (23,572     (148,864
  

 

 

   

 

 

 

Proved Reserves, December 31, 2010

     381,876        629,840   
  

 

 

   

 

 

 

Proved developed reserves as of:

    

December 31, 2009

     211,223        363,997   
  

 

 

   

 

 

 

December 31, 2010

     304,631        500,011   
  

 

 

   

 

 

 

Proved undeveloped reserves as of:

    

December 31, 2009

     75,049        139,843   
  

 

 

   

 

 

 

December 31, 2010

     77,245        129,829   
  

 

 

   

 

 

 

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

As of December 31, 2009, future cash inflows were computed by applying the 12 month arithmetic average of the first of month price for January through December 31, 2009, which resulted in benchmark prices of $61.18 per barrel for crude oil and $3.87 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2009 of $50.60 per barrel of oil and $3.67 per Mcf for natural gas.

As of December 31, 2010, future cash inflows were computed by applying the 12 month arithmetic average of the first of month price for January through December 31, 2010, which resulted in benchmark prices of $79.43 per barrel for crude oil and $4.38 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2010 of $69.54 per barrel of oil and $4.12 per Mcf for natural gas.

 

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The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized Measure

The following table presents the standardized measure of discounted future net cash flows as of December 31, 2009 and 2010 related to proved oil and gas reserves for the oil and gas working interests acquired by the Company on July 29, 2011 (excluding the Separate Interests described in Note 1):

 

     2009     2010  

Future cash inflows

   $ 16,331,439      $ 29,151,354   

Future production costs

     (8,477,510     (13,800,670

Future development costs

     (964,486     (964,486

Future income taxes

     —          (2,162,972
  

 

 

   

 

 

 

Future net cash flows

     6,889,443        12,223,226   

10 percent annual discount

     (3,116,967     (6,027,697
  

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 3,772,476      $ 6,195,529   
  

 

 

   

 

 

 

The present value (at a 10% annual discount) of future net cash flows from proved reserves is not necessarily the same as the current market value of such oil and gas reserves. The estimated discounted future net cash flows from proved reserves is based on average prices realized in the preceding year and on costs in effect at the end of the year for such properties. However, actual future net cash flows from these oil and gas properties will also be affected by factors such as actual prices received for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the production of oil and gas and the incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor used to calculate discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the properties, or the oil and gas industry in general.

 

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Changes in Standardized Measure

A summary of changes in the standardized measure of discounted future net cash flows for the oil and gas working interests acquired by the Company on July 29, 2011, is as follows for the years ended December 31, 2009 and 2010:

 

     2009     2010  

Standardized measure of discounted future net cash flows, beginning of year

   $ 4,237,566      $ 3,772,476   

Sales of oil and gas, net of production costs and taxes

     (465,090     (746,856

Net changes in oil and gas prices and production costs

     —          1,988,196   

Changes in development costs

     —          (100,618

Revisions in previous quantity estimates and other

     —          2,001,471   

Net changes in income taxes

     —          (1,096,388

Accretion of discount

     —          377,248   
  

 

 

   

 

 

 

Standardized measure of discounted future net cash flows, end of year

   $ 3,772,476      $ 6,195,529   
  

 

 

   

 

 

 

Estimates of net proved reserves as of December 31, 2008 in accordance with SEC guidelines were not prepared. Accordingly, the changes in the standardized measure for 2009 do not include revisions in prior estimates, net changes in prices and production costs, accretion of discount or timing and other differences. No acquisition, drilling or other development activities occurring on the Properties during 2009 and 2010 and, accordingly, no amounts are shown for these activities in computing the changes in the standardized measure for 2009 and 2010.

 

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