CORRESP 1 filename1.htm Correspondence

Heartland

Oil and Gas Corporation

September 6, 2006

United States Securities and Exchange Commission

Division of Corporation Finance

Attn: Jonathan Duersch

100 F Street, NE

Washington, DC 20549-7010

Ladies and Gentlemen:

Thank you for your August 11, 2006, letter. With this letter we respond to your comments. For your convenience, we restate each of your comments in italics above our response. We are also sending you a courtesy paper copy which is accompanied by two copies each of our 2005 Form 10-K/A2 and our March 2006 Form 10-Q/A, as supplemental information, one of each marked to show changes from our reports as initially filed, and one of each marked to show changes from our draft amended reports as sent to you on August 10, 2006, for your review.

Form 10-K for the Year Ended December 31, 2005

General

1. We note that you have not submitted your Form 10-KSB draft referred to in your response letter as correspondence on Edgar. Please resubmit your entire response letter which includes your proposed Form 10-KSB draft.

Response: On August 17, 2006, we filed on Edgar our Form 10-KSB/A (Amendment No. 2) which supports our response.

2. We note your disclosure provided in Form 8-K filed on June 12, 2006, suggesting you may be required to revise your financial statements to correct accounting errors. Additionally, we note in your most recent response letter that you have proposed to restate your financial statements related to dividends and the classification of your Series A and B preferred shares from permanent to temporary equity for fiscal years ended December 31, 2005 and 2004. Please tell us whether or not you considered the requirements of Item 4.02 of Form 8-K and describe how you concluded your previously issued financial statements are reliable in light of the error corrections. Tell us whether or not your auditors agree with your conclusion.

Response: We considered the requirements of Item 4.02 of Form 8-K, and filed a Form 8-K on August 17, 2006, reporting in Item 4.02 that on August 15, 2006, our board of directors determined that our previously issued financial statements for 2005 and 2004 were no longer reliable. Our auditors agreed with our conclusions contained in our Form 8-K filed on August 17, 2006.

Balance Sheet, page F-3

3. It appears your Series B shares have a liquidation preference. Accordingly, please provide parenthetical disclosure of the liquidation preference value on the face of your balance sheet. Refer to paragraph 6 of SFAS 129.

 

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Response: In our amended 2005 Form 10-K, our amended March 2006 Form 10-Q and our June 2006 Form 10-Q we provided parenthetical disclosure of the liquidation preference value of our Series B shares. We will continue to do so in future filings.

Operations Statement, page F-4

4. We note that not all periods have been restated, although you have designated the entire presentation as “restated” within the title of the operations statement. Please revise your presentation to more accurately label the specific periods which have been “restated.”

Response: In our amended 2005 Form 10-K and our amended March 2006 Form 10-Q, we revised our presentation to accurately label the specific periods which have been restated.

Oil and Gas Property, F-7

5. We note your response to prior comment three and are unable to agree with your conclusion. In this regard it is unclear how you determined that a value equal to your standardized measure of discounted future net cash flows before income tax considerations is an appropriate impairment model. The standardized measure of discounted future net cash flows is not a fair value model and unproved properties are not assessed for impairment under the full cost ceiling test. Please expand your disclosures to describe the method used to determine fair value and quantify the fair value amount of your impaired assets. Additionally, tell us the authoritative accounting guidance supporting your impairment model determination.

Response: At December 31, 2005, we computed the impairment of our proved reserves using the cost center ceiling test in accordance with the Full Cost rules in section (c) of SEC Regulation S-X, Rule 4.10, specifically, Rule 4-10 (c) (4), Limitation on capitalized costs. That calculation happened to be equal to our standardized measure of discounted future cash flow before income tax because:

1. We established proved reserves for the first time on December 31, 2005. Prior to that we had not had any proved reserves.

2. We did not begin producing and selling the proved reserves until February 2006. Therefore, production, which normally is part of the ceiling test calculation, was zero through December 31, 2005.

3. Income tax, which is normally part of the ceiling test, was zero because we will never pay any income tax on the December 31, 2005, proved reserves because such tax will be fully offset by our tax net operating loss carryforward, which is vastly larger (more than 10 times) than our proved reserves.

We did not assess for impairment our unproved property under the full cost ceiling test. Rather, we assessed it in accordance with the provisions of FAS 144. In our restated financial statements in our amended 2005 Form 10-K, we expanded our disclosures to describe the method used to determine fair value, and quantified the fair value amount of our impaired assets, as shown with the marks in the portions of Notes 1 and 3 shown below.

Note 1 - Organization, Operations and Significant Accounting Policies

Oil and Gas Property

We utilize the full cost method to account for our oil and gas property. Accordingly, we capitalize all cost associated with acquisition, exploration and development of oil and gas reserves, including such cost as leasehold acquisition cost, capitalized interest cost relating to unproved property, geological expenditures, tangible and intangible exploration and development cost including direct internal cost, to the full cost pool. When our oil and gas property commences production, we will deplete the capitalized cost, including estimated future cost to develop the reserves and estimated abandonment cost, net of salvage, on the units-of-production method, when a unit is produced, using estimates of proved reserves. We do not amortize cost of unproved property and major development projects, including capitalized interest, if any, until the property commences production. If we determine the future

 

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exploration of unproved properties to be uneconomical, we add the cost of such property to the capitalized cost to be amortized.

We apply a ceiling test to the capitalized cost in the full cost pool, in accordance with the provisions of SEC Regulation S-X, Rule 4-10 (c) (4), Limitation on capitalized costs. The ceiling test limits such cost to the estimated present value, using a ten percent discount rate, of the future net revenue from proved reserves, based on current economic and operating conditions. Specifically, we compute the ceiling test so that capitalized cost, less accumulated depletion and related deferred income tax, do not exceed an amount (the ceiling) equal to the sum of: (A) The present value of estimated future net revenue computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current cost) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (B) the cost of property not being amortized; plus (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (D) income tax effects related to differences between the book and tax basis of the property.

For unproved property, we exclude from capitalized cost subject to depletion all cost directly associated with the acquisition and evaluation of unproved property until we determine whether or not proved reserves can be assigned to the property. Until we make such a determination, we assess the property at least annually to ascertain whether impairment has occurred, in accordance with FASB Statement 144, Accounting for Impairment of Long-Lived Assets. In assessing impairment we consider factors such as historical experience and other data such as primary lease terms of the property, average holding periods of unproved property, geographic and geologic data and market values of comparable unproved property being bought and sold by other parties. We recognize an impairment loss only if the carrying amount of an unproved property is not recoverable from its undiscounted cash flow. We measure an impairment loss as the difference between the carrying amount and the fair value of the asset. We add the amount of impairment assessed to the cost to be amortized subject to the ceiling test.

We account for sales of proved and unproved property as adjustments of capitalized cost with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized cost and proved reserves of oil and gas, in which case we record the gain or loss in the operations statement.

Note 3 - Gas Property

Impairment

In 2005 we recorded an impairment arising from the expiration of certain leases of $73,917, and an impairment of $14,412,743 arising from the oil and gas leases we abandoned in the Forest City Basin in northeast Kansas. In 2005 we also recorded an impairment of $17,112,416 on exploration pilots in the northern part of our acreage, and two coalbed methane exploration pilots in the southern part of our acreage, all in northeast Kansas. We include the impairment losses in exploration expense. We recorded the impairments as of September 30, 2005. The fair value of our impaired unproved property at September 30, 2005, was zero.

In October 2004 we closed the purchase of the unproved gas property from Evergreen Resources. With the acquisition, we concluded we needed an operations office to manage our property in the region of the property, which we opened on November 1, 2004, in Denver. From November 2004 into June 2005 we engaged into our Denver office our chief operating officer, our vice president of operations, our controller and our chief financial officer to manage our oil and gas operations. The responsibilities of this team included the development and evaluation of our U.S. gas property and other responsibilities.

From inception to the present all of our U.S. gas property is located in northeastern Kansas. Operationally we have viewed that property in two geographic areas, the northern area and the southern area. Prior to the Evergreen purchase, Evergreen had drilled several gas wells in the northern area. Those wells vented methane as well as impurities including nitrogen. Evergreen had injected nitrogen to fracture the mineral formations from which the gas was produced, a procedure commonly used for increasing gas production. At the time of the purchase we anticipated

 

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that the nitrogen production would decrease as the nitrogen introduced in the fracturing was produced. We monitored the impurity production from October 1, 2004, forward.

The nitrogen production caused the wells to be uneconomical. By June 2005 the nitrogen production had not yet declined to economic levels. Accordingly, we concluded that we would not as a company incur more exploration cost on the northern property. However, we believed that, given the steady increase in the price of natural gas, other companies with more capital would be interested in purchasing the northern property, likely for an amount equal to or greater than our book value. Accordingly, on July 5, 2005, we engaged a lease broker to find buyers for the leases we had decided not to retain.

The broker conducted a marketing campaign in an effort to find buyers for the leases. The broker established October 31, 2005, as the closing date for prospective buyers to make offers on the property. On October 31, 2005, the broker advised us that, although there were interested parties, it had not yet received any offers for any of the leases. Because we had not yet finalized the accounting for the quarter ended September 2005, we fully impaired those leases as of September 30, 2005.

As of December 31, 2004, we had concluded that no impairment related to the above property was necessary because we had just acquired most of the property three months earlier and had just begun our evaluation of the property.

At December 31, 2005, we owned unproved property in northeast Kansas with a cost of $1,776,322 which we did not impair because the fair value of the property exceeded the cost.

During the fourth quarter of 2005, we computed a ceiling test limitation that was charged against our oil and gas property of $3,293,952 that is reflected as impairment of oil and gas property in the operations statement.

To summarize our impairment assessment process during 2005, we can group all of our gas property into three groups:

 

  1. Our property which was under development in 2005 (or immediately adjacent to property under development) and on which we established proved reserves as of December 31, 2005. We evaluated this property for impairment at December 31, 2005 by use of the ceiling test, as described above.

 

  2. Our property which we decided to offer for sale in 2005. We fully impaired this property at September 30, 2005, as described above.

 

  3. Our unproved property which we concluded we would not offer for sale in 2005. We assessed this property for impairment at December 31, 2005, and determined that it was not impaired because the fair value of the property exceeded the cost.

Changes in Standardized Measure of Discounted Future Cash Flow, page F-17

6. We note your revisions within the tabular presentation of changes in standardized measure of discounted future net cash flows. It appears that the change has been attributed to one line item, extensions and discoveries. Please revise your presentation to allocate values to the appropriate components for which change occurred, consistent with your disclosure of the standardized measure of discounted future net cash flows.

Response: Prior to December 2005 we had no proved reserves. The second half of Illustration 5 in FAS 69 recommends a format for presenting “the principal sources of change in the standardized measure of discounted future net cash flows during” a given year. One of the components of the illustration is “Extensions, discoveries, and improved recovery, less related costs”. All of the other components in the illustration relate to changes from a Standardized Measure at the beginning of the year. We had no Standardized Measure at the beginning of the year. In fact, we had no Standardized measure until December 2005. All of the change in our standardized measure came from discoveries. Thus, the amount for each of the other components of the table for 2005 was zero. GAAP provides that when the amount of a required disclosure is zero, the disclosure is generally not required. Because each of the components other than discoveries was zero, the only line we put into the table was Extensions and Discoveries.

 

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Form 10-Q for the Quarter Ended March 31, 2006

7. We note your response indicating that you will incorporate the appropriate revisions in your interim report on Form 10-QSB as necessary to comply with all applicable comments written on your annual report on Form 10-KSB above.

Response: We have incorporated the appropriate revisions in our amended March 2006 Form 10-Q and our June 2006 Form 10-Q as necessary to comply with all applicable comments in each of the three letters we have received from you.

Closing

We have amended our 2005 Form 10-K and our March 2006 Form 10-Q, responsive to all comments in the three letters we have received from you, as applicable. Our June 2006 Form 10-Q was also responsive to all of your comments, as applicable.

 

Sincerely yours,

/s/ Robert L. Poley

Robert L. Poley, CPA

Chief Financial Officer

Director

Heartland Oil and Gas Corp.

Direct telephone: 303-530-9504

 

1625 Broadway – Suite 1480, Denver, Colorado 80202    Telephone 303 405-8450 Facsimile 303 405-8451