July 6, 2009
Via EDGAR
Ms. Jill S. Davis
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 April 21, 2009
File No. 1-32496
Dear Ms. Davis and 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 (“Amendment No. 1”) and Response Letter dated April 21, 2009 (the “Response Letter”) set forth in the letter from the Securities and Exchange Commission (“SEC”) dated June 1, 2009.
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 our prior comment one from our letter dated March 24, 2009. With regard to such activities, please modify your disclosures to provide the following additional information:
· Expand your risk factors and management’s discussion and analysis to discuss in detail the risks involved in secondary and tertiary exploration activities;
Response:
We propose modifying our risk factors similar in concept to the following:
Exploration and development drilling and the application of waterflood and EOR techniques may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations or our application of waterflood or EOR techniques. The new wells we drill or participate in, whether undertaken in primary drilling or utilizing waterflood or EOR techniques, may not be productive and we may not recover all or any portion of our investment. The engineering data and other technologies we use do not allow us to know conclusively, prior to beginning a project, that crude oil or natural gas is present in the reservoir or that those reserves can be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to generate an economic return sufficient to cover drilling, operating and other
costs, or if our application of waterflood or EOR techniques are not successful. Further, our drilling and other operations may be curtailed, delayed or canceled as a result of a variety of factors, including but not limited to:
· unexpected drilling conditions;
· title problems;
· pressure or irregularities in formations;
· equipment failures or accidents;
· volatility in crude oil and natural gas prices,
· adverse weather conditions; and
· increases in the costs of, or shortages or delays in the availability of, chemicals, drilling rigs and equipment.
Certain of our current development and exploration (waterflood or EOR techniques where no proved waterflood or EOR reserves have previously been recorded) activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all oil and gas activities, whether developmental or exploratory, involves these risks, exploratory activities involve greater risks of failure to find and produce commercial quantities of oil or gas.
· Expand your liquidity discussion to include the sources and uses of funding for your secondary and tertiary activities, and disclose a commodity price sensitivity analysis related to your secondary and tertiary activities (i.e. at what prices will your ASP technology become uneconomical);
Response:
For our next Annual Report on Form 10-K for the year ended June 30, 2009, we have provided our proposed expanded disclosures in Disclosure Exhibit A. The underlined text represents new disclosure to address the comments raised by the SEC comment letter.
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· Clarify in your disclosure that your secondary and tertiary activities performed on properties that are in the exploration stage are not development activities and as such that any related capitalized costs represent deferred charges;
Response:
For our next Annual Report on Form 10-K for the year ended June 30, 2009, we have provided our proposed expanded disclosures as of June 30, 2008 in Disclosure Exhibit B.
· Explain how the activities related to your secondary and tertiary recovery meet the requirements for deferral provided in paragraph 19 of SFAS and provide all disclosures required by FSP FAS 19-1; and,
Response:
Paragraphs 19 and 31-34 of SFAS 19 address the capitalization of costs associated with exploratory wells. Paragraph 19 requires that an assessment be made of whether an exploratory well has found proved reserves once the drilling of the exploratory well is complete. If the well has found proved reserves, the associated costs are added to the company’s oil and gas properties. If the activity does not generate proved reserves, the associated costs are expensed. If the well has found reserves, but those reserves cannot be classified as proved when the drilling has been completed, the associated costs continue to be deferred until such time as a determination can be made if the well has found sufficient reserves to justify its completion as a producing well, and progress is being made in assessing the reserves and economic and operating viability of the project. Ultimately, if a well has found proved reserves, the costs associated with the project are added to the proved properties base and depleted based on its proved developed reserves using the units of production method.
As discussed in our April 21, 2009 response, we believe that costs incurred in secondary and tertiary exploratory activities most closely resemble costs to drill and equip exploratory wells. Extending this established similarity between exploratory secondary and tertiary projects and drilling and equipping exploratory wells to the requirements of paragraph 19, the costs incurred in the secondary and tertiary activities should be deferred until the project has reached a state that is equivalent to a well that has completed drilling. Upon reaching the completion stage, the requirements of paragraphs 19 and 31-34 should be applied to determine if the project is successful. To determine the state of a secondary or tertiary project that is equivalent to the state of a well that has completed drilling, we start with an evaluation of what characteristics describe a well that has completed drilling. These characteristics include:
· The well has reached its target depth,
· All steps necessary to facilitate an assessment of whether reserves exist, that is, all steps necessary to gain access to the potential producing formation and gather evidence about its nature, either through core samples or flow tests, have been completed, and
· The construction of completion infrastructure, such as wellhead equipment, tank batteries, and production tubing, has not been initiated.
For both a secondary and tertiary project, we believe the most relevant characteristic to compare is that of a well reaching its target depth. For a secondary or tertiary ASP project, the equivalent of a well reaching target depth is when the injection of material reaches a target pore volume injected percentage (PVI). Once a project has reached the target PVI, an evaluation of whether the project has found proved reserves commences.
Based on our analysis of these characteristics, we believe that a waterflood or ASP project has reached a stage equivalent to a well for which drilling has been completed when the amount of injected material has reached a predefined pore volume target percentage (PVI). Based on this conclusion, costs should continue to be deferred pending the earlier of injection totals reaching the PVI or injection activities being abandoned. If prior to reaching the PVI, the injection of material is abandoned, the project would be deemed unsuccessful and all capitalized deferred costs expensed.
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Secondary and tertiary projects can take significantly longer to complete than conventional primary drilling, with the length of time influenced by where in the primary production decline curve the project is initiated, access to injection materials, and general reservoir properties. Under Disclosure Exhibit B, we discuss the expected time table for project completion, specific completion steps, and future estimated drilling and equipping costs for our exploratory projects.
· Expand your existing disclosures throughout your document to ensure the costs related to exploratory secondary and tertiary activities are presented as exploration costs.
In your response to this comment, please provide us with a sample of your proposed expanded disclosures.
Response:
For our next Annual Report on Form 10-K for the year ended June 30, 2009, we have provided our proposed expanded disclosures in Disclosure Exhibit B.
2. Please tell us whether or not the ASP injected will be recovered and resold.
Response:
The chemicals injected in our ASP projects cannot be recovered and resold.
Please let me know if the responses are acceptable. You can reach me at 817.869.1037.
Very truly yours,
/s/ Michael J. Ricketts |
|
Michael J. Ricketts
Vice President — Principal Accounting Officer
Direct Phone Number: 817.869.1037
Direct Fax Number: 817.698.0796
mike@canopetro.com
cc: Phillip Feiner
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Disclosure Exhibit A
Liquidity and Capital Resources
For the nine months ended March 31, 2009, our primary sources of cash were receipts from the sale of crude oil and natural gas production, issuance of common stock, net borrowings under our credit agreements, sales of oil and gas properties, payments from in-the-money commodity derivative contracts, and settlements from third parties and the W.O. Settlement pertaining to the Panhandle fire litigation as discussed in Note 13. Our cash receipts from sales are discussed in greater detail under “Results of Operations — Operating Revenues.” The sources of cash are discussed in greater detail below:
· On July 1, 2008, we received net proceeds of $53.9 million for the issuance of 7.0 million shares of our common stock. The net proceeds were used to pay down long-term debt due under our senior credit agreement (Note 3).
· On October 1, 2008, we sold our wholly-owned subsidiary, Pantwist, LLC (“Pantwist”), for $42.7 million ($40.0 million net of closing adjustments of $2.1 million of discontinued operating income recorded in the first quarter of the 2009 Fiscal Year and $0.6 million of advisory fees - Note 2).
· On December 2, 2008, we sold our interests in the Corsicana Properties for $0.3 million (Notes 2 and 12).
· During October 2008, we sold certain uncovered “floor price” commodity derivative contracts covering July 2010 to December 2010 for $0.6 million to our counterparty, and during November 2008, we sold all remaining uncovered “floor price” commodity derivative contracts covering November 2008 through June 2010 for $2.6 million to our counterparty. We recorded a realized gain of $0.7 million and an unrealized gain of $1.3 million as a result of these transactions.
· On October 31, 2008, an independent electrical contractor paid us $6.0 million (its full insurance policy limits) in exchange for a full release of any existing or future claims related to wildfires that began on March 12, 2006 in Carson County, Texas. The $6.0 million has been fully expended to cover the settlements discussed in Note 13.
During the nine-month period ended March 31, 2009, our cash outlays were primarily for:
· Lease operating expense, general and administrative expenses, and the settlement of fire litigation claims, which are discussed in greater detail under “Results of Operations — Operating Expenses.”
· Capital expenditures, which are discussed in greater detail under “Drilling Capital Development and Operating Activities Update.”
· The repurchase of 22,948 shares of Series D Convertible Preferred Stock, including accrued and unpaid PIK dividends relating to such shares for approximately $10.5 million, which is discussed in greater detail in Note 6.
As discussed under “Drilling Capital Development and Operating Activities,” we have incurred $44.7 million of capital expenditures through March 31, 2009. $2.4 million of the $44.7 million we have incurred pertains to secondary and tertiary exploration activities (new projects where no secondary or tertiary reserves have previously been recorded). We are implementing two projects that involve secondary and tertiary exploration activities to oil and gas properties that have existing reserves associated with primary or secondary recovery activities, respectively. Our two current projects are the Duke Sands waterflood at our Desdemona Properties (currently has primary production) and the ASP tertiary recovery pilot project at the Nowata Properties (currently has secondary production). These exploration activities entail more risk compared to our development activities where proved secondary or tertiary reserves exist since these two projects did not have proved incremental reserves prior to implementation of the project. We estimate the crude oil price necessary to sustain the long-term economic viability
of these two projects is approximately $45 - $50 per barrel. This price could vary based on several factors, including project location and type of reservoir.
As discussed in Note 4, at March 31, 2009, our remaining available borrowing capacity under the senior credit agreement is $31.3 million. We intend to draw down from our available borrowing capacity to cover shortfalls in our cash flow from operations to fund our operations, capital development program as previously discussed under “Drilling Capital Development and Operating Activities Update,” for general corporate purposes and for selective acquisitions. Pursuant to the terms of the ARCA, the borrowing base is to be redetermined based upon reserves at May 1, 2009 and again on June 30, 2009. We have begun the process with our bank group and cannot determine at this time if there will be any changes to our borrowing base.
At March 31, 2009, our cash balance was $0.3 million. For the nine months ended March 31, 2009, our cash used in operations was $5.1 million as compared to cash provided by operations of $13.2 million for the nine months ended March 31, 2008. Cash used in operations for the nine months ended March 31, 2009 was negatively impacted by the $8.1 million for settlement payments related to the resolution of fire litigation. Cash provided by operations for the nine months ended March 31, 2008 was positively impacted by $6.0 million related to the release of restricted cash received from our insurance providers.
We believe the combination of cash on hand, cash flow generated from the expected success of prior capital development projects and debt available under our credit agreements is sufficient to finance our operations, contractual obligations and capital expenditure program, including costs incurred for secondary and tertiary exploration activities (as previously discussed in the section titled “Drilling Capital Development and Operating Activities Update”).
7/2/2009
Disclosure Exhibit B
Oil and Gas Properties and Equipment
We follow the successful efforts method of accounting, capitalizing costs of successful exploratory projects and expensing unsuccessful exploratory projects. All developmental costs are capitalized. We are primarily engaged in the acquisition and development of proved reserves. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisition and development activities and deferred exploratory drilling costs. 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.
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 prospectively on a quarterly basis based on updated engineering information for our proved developed reserves. 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 $13.0 million and $6.0 million, respectively, are deferred costs related to exploratory activities as described below.
Costs incurred for Exploration of Oil and Gas Reserves Using Secondary and Tertiary Techniques
As part of our growth strategy, we incur costs associated with secondary and tertiary techniques that are exploratory activities as opposed to development. This exploration occurs within reservoirs for which we already have proved developed reserves recorded from earlier development. Exploratory secondary and tertiary drilling and equipping costs include converting primary production wells to injection wells, installation of injection facilities, and injecting materials. When conducting secondary and tertiary drilling and equipping activities, we defer 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, the drilling and equipping costs incurred in the project are added to the depletion base and depreciated using the units of production method based on proved developed reserves. Currently we have two projects, one secondary and one tertiary, that are exploratory. Secondary and tertiary projects typically take longer to complete than drilling primary production wells, and as a result, the period during which exploratory drilling costs are deferred is longer. The table below summarizes the drilling and equipping costs incurred and deferred related to exploratory secondary and tertiary projects that are pending determination of success.
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| Year ended June 30, 2008 |
| Year ended 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 |
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Our exploratory secondary and tertiary projects are evaluated to determine whether they have found proved reserves when the project is substantially complete. We consider a secondary or tertiary project to be substantially complete when the amount of material injected reaches our target pore volume percentage (“PVI”) determined necessary to stimulate response. Our two exploratory projects are the Duke Sands waterflood at our Desdemona Properties and the ASP tertiary recovery pilot project at the Nowata Properties. As of June 30, 2008, neither of these projects is
complete, and as such, all of the costs associated with these two projects have been deferred. The Duke Sands project is expected to take an additional nine to twelve months to reach the PVI threshold at which response is expected to occur. It is anticipated that an additional $1.2 million will be required to complete this project. The Nowata ASP project is expected to take an additional nine to twelve months before the final chemical flush is complete and the response can be evaluated. It is anticipated that an additional $2.5 million will be required to complete the project.
The following table provides an aging of deferred exploratory drilling costs based on the date the project was initiated.
|
| 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 of one to three years |
| 6,115 |
| 75 |
| ||
Balance at June 30 |
| $ | 13,475 |
| $ | 6,115 |
|
Number of projects that have exploratory costs that have been capitalized for a period of one to three years |
| 2 |
| 0 |
| ||
The following table reflects the net change in deferred exploratory project costs during fiscal years 2008, 2007, and 2006:
|
| Year ended June 30, |
| |||||||
In Thousands |
| 2008 |
| 2007 |
| 2006 |
| |||
Balance at July 1 |
| $ | 6,115 |
| $ | 550 |
| $ | 75 |
|
Additions pending the determination of proved reserves |
| 7,360 |
| 5,565 |
| 475 |
| |||
Reclassifications to proved property and equipment |
| — |
| — |
| — |
| |||
Capitalized exploratory costs charged to expense |
| — |
| — |
| — |
| |||
Balance at June 30 |
| $ | 13,475 |
| $ | 6,115 |
| $ | 550 |
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