April 21, 2009
Via EDGAR
Mr. Mark Wojciechowski
Division of Corporation Finance
United States Securities and Exchange Commission
100 F St., N.E.
Washington, D.C. 20549
Re: Cano Petroleum, Inc.
Form 10-K for the Fiscal Year Ended June 30, 2008
Filed September 11, 2008
File No. 1-32496
Amendment No. 1 to Form 10-K for the Fiscal Year Ended June 30, 2008
Filed October 28, 2008
File No. 1-32496
Response Letter dated March 6, 2009
File No. 1-32496
Dear Mr. Wojciechowski:
On behalf of Cano Petroleum, Inc. (the “Company”), we are submitting the Company’s responses to the comments to the Company’s Form 10-K for the fiscal year ended June 30, 2008 (the “Form 10-K”), Amendment No. 1 to the Form 10-K and Response Letter dated March 6, 2009 set forth in the letter from the Securities and Exchange Commission (“SEC”) dated March 24, 2009 (the “SEC Letter”).
The staff’s comments are set forth below and the Company’s responses are set forth after the staff’s comments.
1. We note your response to prior comment one from our letter dated February 20, 2009. Given that you determined the sales contracts with Valero Marketing Supply Co., Eagle Rock Field Services, LP, Coffeeville Refinery and Marketing, LLC, DCP Midstream, LP, and Sunoco, Inc. may be considered material contracts, please amend Part IV of your Form 10-K to include such contracts as exhibits.
Response: The Company is prepared to file as exhibits to Amendment No. 2 to the Form 10-K (“Amendment No. 2”) the sales contracts described above and any amendments thereto that contain terms that were effective on or after July 1, 2007, which is the beginning of the period covered by the Form 10-K. The Company believes that these sales contracts and amendments are the only material agreements related to these sales contracts on or after July 1, 2007. In connection with such filing, the Company is also prepared to provide a FOIA Confidential Treatment Request to the SEC requesting
confidential treatment for certain confidential pricing and fee terms contained in certain of the sales contracts and amendments, which the Company will submit concurrent with the filing of Amendment No. 2.
At the staff’s request, the Company is not filing Amendment No. 2 at this time, and will wait to make such filing until the issues raised in Comment 2 below have been resolved, or until the staff instructs the Company to make such filing.
2. Your response to prior comment three from our letter dated February 20, 2009 explains that costs incurred for waterflood and alkaline-surfactant-polymer projects prior to the establishment of proved reserves are capitalized. The guidance provided in SFAS 19 reflects an activity based model of accounting for oil and gas activities. For costs related to enhanced oil recovery incurred during the exploration stage, please explain why you believe your accounting policy regarding capitalization of such cost prior to the establishment of proved reserves is consistent with the guidance found in paragraphs 16-24 of SFAS 19.
As part of your response, please discuss the specific nature of the costs incurred prior to establishing proved reserves, and tell us whether such costs are similar to the types described in paragraph 17, 18, or 19 of SFAS 19.
Response: The guidance found in SFAS 19 addresses the nature of costs in the oil and gas industry. In recognizing successful efforts as the only appropriate method for accounting for oil and gas activities, the FASB noted that successful efforts accounting is the approach most consistent with the promulgated financial accounting framework. In that framework, an asset is an economic resource that is expected to provide future benefit. Costs that do not relate directly to specific assets having identifiable future benefits normally are not capitalized. In the oil and gas industry, the expected future economic benefits the enterprise is attempting to obtain are oil and gas reserves. With that framework in mind, the board crafted the rules found in paragraphs 16-24 to capitalize costs directly associated with successful exploration activities, and to expense costs associated with unsuccessful activities and other costs not directly associated with successful exploration.
SFAS 19 does not explicitly address costs related to secondary (waterflood) and tertiary (chemical, CO2, etc.) projects, instead focusing on costs incurred in the exploration and development of primary production. Paragraph 17 of SFAS 19 states:
Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
a. Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.
b. Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
c. Dry hole contributions and bottom hole contributions.
d. Costs of drilling and equipping exploratory wells.
e. Costs of drilling exploratory-type stratigraphic test wells.
It is important to note that while the board listed most of the types of costs that occur in the exploration for oil and gas reserves, paragraph 17 is not comprehensive, as evidenced by the presence of the word “principal” which the Merriam-Webster Dictionary defines as “most important, consequential, or influential”. Paragraphs 18-20 discuss the accounting treatment of the costs listed in paragraph 17, requiring the capitalization of costs incurred in the drilling and equipping of exploratory wells (item d) and exploratory-type stratigraphic wells (item e) pending determination of whether the project is successful in finding proved reserves. Nowhere in SFAS 19 does the board state or imply that paragraph 17 is all-inclusive, or that costs not listed in paragraph 17 as principal exploration costs should be expensed as incurred; instead, the standard is silent with respect to costs not listed.
Costs to explore for oil and gas reserves using secondary and tertiary techniques are not listed by the standard as a principal type of exploration cost. Although not listed, these costs are appropriately considered exploration costs when incurred in the pursuit of oil and gas reserves not already recorded by the Company as proved. Since the board did not address these costs, the industry practice looks to the intent of the FASB and to the types of costs listed in paragraph 17 to determine which type of cost secondary and tertiary costs most closely resemble.
The types of costs incurred to explore for oil and gas reserves using secondary and tertiary techniques include:
· Costs to drill and equip injection wells, including costs to convert primary production wells to injectors,
· Costs to gain access to and provide transportation for injection materials,
· Costs to inject materials into the formation, and
· Costs to monitor and refine the progress of injected materials in the formation.
In a secondary or tertiary recovery project, all of the costs listed above are directly related to specific assets having identifiable future benefits — namely the reserves for which exploration or development is occurring. While in the exploration stage, the probability that the reserves exist is not yet conclusive to the point where the reserves can be classified as proved, though typically the probability is such that a classification of probable reserves under the new SEC Release No. 33-8957 framework can be justified. As a point of comparison, just as with exploration using primary recovery techniques, costs to explore for oil and gas reserves using secondary and tertiary techniques are typically incurred prior to the determination of whether the project has found proved reserves, often requiring one to two years to evaluate success (e.g. deepwater Gulf of Mexico projects). Using the model shown in paragraphs 17-19, the type of cost most closely resembling costs incurred in the exploration for oil and gas reserves using secondary and tertiary techniques are costs of drilling and equipping exploratory wells (item e in the paragraph 17 model). Using this corollary example, the Company believes that costs incurred to explore for oil and gas reserves using secondary and tertiary techniques should be capitalized until a determination can be made whether proved reserves have been found. In addition, the Company has internally recorded probable reserves of 9.0 million BOE associated with exploratory secondary and tertiary recovery activities, the existence of which is the basis for its business model, and supports the conclusion that an asset exists.
A similar situation occurs when a company hydraulically fractures a well after drilling has been completed. In some formations with low permeability, a hydraulic fracture is required to make the well economic, a key requirement in the discovery of proved reserves. Hydraulic fracturing is
not a cost to drill and equip a well in the literal sense, since the activity is directed at the formation surrounding the well, and is designed to change one of the characteristics of the rock. Injecting water into a formation during a secondary recovery project and other substances during a tertiary recovery project are activities likewise designed to change the characteristics of the formation, though the focus is to change pressure conditions in secondary injection. The Company cannot discern a difference between these types of costs when analyzed using the model provided in SFAS 19.
The Company has observed diversity in practice in the industry related to the capitalization of costs incurred in the exploration for reserves using secondary and tertiary techniques. While many companies capitalize these costs under the rationale described above, others expense these items on the basis that they lack sufficient knowledge to attribute the costs to assets having identifiable future benefits. This diversity in practice is described on page 563 of Petroleum Accounting (“Petroleum Accounting”, 6th Edition, by Brock, Carnes, and Justice), as well as earlier editions. In addition, the industry has consistently documented the diversity since the early 1980s through scholarly journals such as the Petroleum Accounting and Financial Management Journal (a selection of which is cited in the endnotes of this response). As stated previously, the Company believes it has sufficient evidence that the costs it incurs in its secondary and tertiary projects directly relate to assets having identifiable future benefits, and therefore should be capitalized.
The amount of costs associated with secondary and tertiary recovery activities for which no underlying incremental proved reserves exist is material to the Company’s financial statements. The following table illustrates the affect reclassification to exploration expense could have on operating income for the year ended June 30, 2008.
|
| Year Ended June 30, |
| |
In Thousands |
| 2008 |
| |
Income from Operations |
| $ | 5,677 |
|
Less Exploration Expense: |
|
|
| |
Injected Materials |
| 2,950 |
| |
Exploration Infrastructure |
| 4,410 |
| |
Total Exploration Expense |
| 7,360 |
| |
Income (loss) from Operations |
| (1,683 | ) | |
Given that the issue is material to the Company and the fact that diversity in practice exists, the Company proposes that it may be appropriate to disclose in the footnotes of its financial statements the policy used with respect to these costs and the amount of costs associated with the policy. For illustrative purposes, such a disclosure would be similar in concept to the following:
Oil and Gas Properties and Equipment
We follow the successful efforts method of accounting. All developmental costs are capitalized. We are predominately engaged in the acquisition and development of proved reserves as opposed to exploration activities. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisitions and development activity. Capitalized overhead costs that directly relate to our drilling and development activities were $0.8 million and $0.5 million, for the years ended June 30, 2008 and 2007, respectively. We
recorded capitalized interest costs of $2.5 million and $0.3 million for the years ended June 30, 2008 and 2007, respectively. We record capitalized interest for projects that have an expected cost of at least $1.5 million and a development period of at least six months.
Depreciation and depletion of producing properties is computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.
Our unit-of-production amortization rates are revised on a quarterly basis. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until impairment occurs. As of June 30, 2008 and 2007, capitalized costs related to waterflood and alkaline-surfactant-polymer projects that are in process and not subject to depletion amounted to $47.6 million and $22.8 million, respectively, of which $13.4 million and $6.0 million, respectively, related to exploratory activities as described below.
Costs incurred for Exploration of Oil and Gas Reserves Using Secondary and Tertiary Techniques
As part of its EOR strategy, the Company incurs costs associated with secondary and tertiary techniques that are exploratory in nature. These costs include converting primary production wells to injection wells, installation of injection facilities, and injecting materials. When conducting secondary and tertiary activities, the Company capitalizes costs associated with these projects pending a determination of whether the project is successful. If the project is determined not to be successful, all of the costs associated with the project are recorded as exploration expense in the period in which such determination is made. If the project is successful, capital invested to develop the project is depreciated using the units of production method. The Company has observed that some companies in the industry expense exploratory secondary and tertiary costs as incurred until a project has been deemed successful. The table below summarizes the costs incurred and capitalized by the Company related to exploratory secondary and tertiary projects. Had the Company chosen to expense these costs, operating income and oil and gas properties would be lower.
|
| June 30, 2008 |
| June 30, 2007 |
| ||||||||||||||
In Thousands |
| Secondary |
| Tertiary |
| Total |
| Secondary |
| Tertiary |
| Total |
| ||||||
Costs of Injected Materials |
| $ | 2,000 |
| $ | 2,000 |
| $ | 4,000 |
| $ | 700 |
| $ | 350 |
| $ | 1,050 |
|
Cost of Project Infrastructure |
| $ | 8,000 |
| $ | 1,400 |
| $ | 9,400 |
| $ | 4,360 |
| $ | 630 |
| $ | 4,990 |
|
Total Costs |
| $ | 10,000 |
| $ | 3,400 |
| $ | 13,400 |
| $ | 5,060 |
| $ | 980 |
| $ | 6,040 |
|
The following table provides an aging of capitalized exploratory costs based on the date the project was completed and the number of projects for which
exploratory costs have been capitalized for a period greater than one year since the completion of the project:
|
| Year Ended June 30, |
| ||||
In Thousands |
| 2008 |
| 2007 |
| ||
|
|
|
|
|
|
|
|
Capitalized exploratory costs that have been capitalized for a period of one year or less |
| $ | 7,360 |
| $ | 6,040 |
|
Capitalized exploratory costs that have been capitalized for a period greater than one year |
| $ | 6,040 |
| $ | 0 |
|
Balance at June 30 |
| $ | 13,400 |
| $ | 6,040 |
|
Number of projects that have exploratory costs that have been capitalized for a period greater than one year |
| 2 |
| 0 |
| ||
Brock; Carnes; Justice. Petroleum accounting principles, procedures & issues, 6th edition. Denton, Texas: Professional Development Institute, 2007
May, E.S.; Pearson, H.O. “Treatment of Costs CO2 Injectants in Enhanced Recovery Projects” Journal of Extractive Industries Accounting 3-2 (1984): 16-18.
“Accounting for CO2 Injection Costs.” Journal of Petroleum Accounting 4-3 (1985): 17-21.
Brock, Horace. “Accounting Forum.” Petroleum Accounting and Financial Management Journal 10-1 (1991): 22-26.
Please let me know if the responses are acceptable so the Company can finalize and file Amendment No. 2. You can reach me at 214.651.5119.
Very truly yours,
/s/ W. Bruce Newsome |
|
W. Bruce Newsome
Direct Phone Number: 214.651.5119
Direct Fax Number: 214.200.0636
Bruce.newsome@haynesboone.com
cc: Phillip Feiner
