March 6, 2009
Via EDGAR
Mr. Mark Wojciechowski
Mr. James Murphy
Division of Corporation Finance
United States Securities and Exchange Commission
100 F St., N.E.
Washington, D.C. 20549
| | Form 10-K for the Fiscal Year Ended June 30, 2008 |
File No. 1-32496
Amendment No. 1 to Form 10-K for the Fiscal Year Ended June 30, 2008
File No. 1-32496
Response Letter dated January 21, 2009
File No. 1-32496
Dear Messrs. Wojciechowski and Murphy:
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 regarding the disclosure identifying your material customer relationships pursuant to Item 101 of Regulation S-K and the contracts related to such significant customers under Item 601 of Regulation S-K. The staff continues to believe that the disclosure required by Item 101 and Item 601 continues to be required. Please revise your disclosure to identify the customers who represent 10% or more of the company’s total operating income, and file the material contracts related thereto. To the extent that the company wishes to include its belief that all of its major customers can be replaced, such disclosure can be included as a belief of the company.
Response: For future Form 10-K filings, we propose to include expanded disclosure similar in concept to the following “underlined and strike-out” disclosure, which for illustrative purposes has been added to the disclosure set forth on page 8 and on page F-8 of the Form 10-K dated June 30, 2008:
p. 8
We sell our crude oil and natural gas production to several independent producers. During the year ended June 30, 2008, 10% or more of our total revenues were attributable to four customers accounting for 33% (Valero Marketing Supply Co.), 18% (Eagle Rock Field Services, LP), 15% (Coffeeville Resources Refinery and Marketing, LLC) and 14% (DCP Midstream, LP) of total operating revenue, respectively.
p. F-8
As previously discussed, we sold our crude oil and natural gas production to several independent purchasers. During the year ended June 30, 2008, we had sales of 10% or more of our total revenues to four customers which represented 33%, 18%, 15% and 14% of total operating revenue, respectively. During the year ended June 30, 2007, we had sales of 10% or more of our total revenues to four customers representing 36%, 18%, 17% and 16% of total operating revenue, respectively. During the year ended June 30, 2006, we had sales to primarily five customers which represented 29%, 25%, 12%, 12% and 10% of total operating revenue, respectively. During the years ended June 30, 2008, 2007 and 2006, we had sales of 10% or more of our total revenues to several customers as shown in the following table:
| | | 2008 | 2007 | 2006 |
| | Valero Marketing Supply Co. | 33% | 36% | 29% |
| | Eagle Rock Field Services, LP | 18% | 18% | 12% |
| | Coffeeville Resources Refinery and Marketing, LLC | 15% | 16% | 25% |
| | DCP Midstream, LP | 14% | 17% | 10% |
| | Sunoco, Inc. | * | * | 12% |
| | | | | |
| | * Less than 10% of operating revenue | | |
In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative customers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost customers. We do not believe that the loss of any single purchaser would have a material adverse effect on our operations. However, the loss of a single purchaser could potentially reduce the competition for our crude oil and natural gas production, which in turn could negatively impact the prices we receive.
We will file the sales contracts with Valero Marketing Supply Co., Eagle Rock Field Services, LP, Coffeeville Refinery and Marketing, LLC and DCP Midstream, LP as exhibits in the next Form 10-Q.
2. We note your response to comment number five from our letter dated December 23, 2008. At this time we are not in a position to agree with your conclusions, and continue to believe you should modify your presentation to report realized and unrealized gains and losses on commodity derivatives in a single line item, and provide further clarifying discussion of the nature and amounts of realized versus unrealized gains and losses within the notes to the financial statements.
Response: For future filings, we will modify our presentation to report realized and unrealized gains and losses on commodity derivatives in a single line item titled “Gains and losses on commodity derivatives.” Also, for future filings, we will modify our footnote disclosure to clarify the nature of realized versus unrealized gains and losses. For future Form 10-K filings, we propose to include expanded disclosure similar in concept to the following “underlined and strike-out” disclosure, which for illustrative purposes has been added to the disclosure set forth on pages F-19 and F-20 of the Form 10-K dated June 30, 2008:
During the years ended June 30, 2008, 2007 or 2006, we had a loss on commodity derivatives of $32.0 million, $0.8 million and $2.7 million, respectively. Our loss on commodity derivatives consists of both realized and unrealized gains and losses as summarized in the table below: there were settlements under our commodity derivatives due to us and paid by us with our counterparty that are accrued as realized gains or losses on commodity derivatives in our consolidated statements of operations that are summarized as follows:
| | | | Years Ending June 30, | |
| | In Thousands | | 2008 | | | 2007 | | | 2006 | |
| | Settlements received | | $ | 504 | | | $ | 963 | | | $ | 541 | |
| | Settlements paid / accrued | | | (3,089 | ) | | | — | | | | — | |
| | Realized gain (loss) on commodity derivatives | | $ | (2,585 | ) | | $ | 963 | | | $ | 541 | |
| | Unrealized loss on commodity derivatives | | | (29,370 | ) | | | (1,810 | ) | | | (3,246 | ) |
| | Loss on commodity derivatives | | $ | (31,955 | ) | | $ | (847 | ) | | $ | (2,705 | ) |
The realized gain (loss) consists of actual cash settlements under our commodity derivatives during the respective reporting periods. The cash settlements received by us were cumulative monthly payments due to us since the NYMEX natural gas and crude oil prices were lower than the "floor prices" set for the respective time period. The cash settlements paid/accrued by us were cumulative monthly payments due to our counterparty since the NYMEX crude oil and/or natural gas prices were higher than the "ceiling prices" set for the respective time period. The cash flows relating to the derivative instrument settlements that are due, but not cash settled are reflected in operating activities on our consolidated statements of cash flows. At June 30, 2008, we had amounts payable to our counterparty of $1.2 million, included in accounts payable on our consolidated balance sheet. At June 30, 2007, we had amounts due from our counterparty of $0.1 million, included in accounts receivable on our consolidated balance sheet.
The unrealized loss on commodity derivatives represents estimated future settlements under our commodity derivatives and is based on We computed our mark-to-market valuations used for our commodity derivatives based on assumptions regarding forward prices, volatility and the time value of money. We compared our valuations to our counterparties' valuations to further validate our mark-to-market valuations. During the years ended June 30, 2008, 2007 and 2006, we recognized unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $29.4 million, $1.8 million and $3.2 million, respectively. Of the $29.4 million amount for the year ended June 30, 2008, $26.5 million pertained to costless collars, which did not require any initial cash outlay and do not involve future cash outlay unless the NYMEX crude oil and natural gas prices exceed the ceiling prices as specified in the table above.
3. Your response to prior comment six explains how you account for costs incurred in the development and production stage for waterflood and alkaline-surfactant-polymer projects. Please tell us if costs related to these improved recovery activities are incurred prior to the recording of proved reserves (i.e. exploration stage), and if so, how such costs are accounted for.
Response: We account for costs incurred for waterflood and alkaline-surfactant-polymer projects in the same manner during the exploratory and production stages. For future Form 10-K filings, we propose to include expanded disclosure similar in concept to the following “underlined and strike-out” disclosure, which for illustrative purposes has been added to the disclosure set forth on page F-7 of the Form 10-K dated June 30, 2008:
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 related to waterflood and alkaline-surfactant-polymer projects are capitalized as Oil and Gas Properties on our balance sheet. These costs are capitalized during the development and exploration periods and are expensed as incurred during the production period. The capitalized costs are not depleted until such project is substantially complete, proved reserves are determined and producing sustainable production occurs, or until an impairment occurs. At 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.
4. We note your response to prior comment eight. For the specific lawsuits discussed, please modify your disclosure to explain whether the risk of loss is probable, reasonably possible, or remote; and whether any amounts have been accrued under the guidance of paragraph 8 of FAS 5. If no accrual for a loss contingency has been made, please expand your disclosure to include an estimate of the possible loss or range of loss or state that such an estimate cannot be made. Refer to paragraph 10 of FAS 5.
Response: Regarding the specific lawsuits discussed in our Form 10-Q for the quarterly period ended September 30, 2008, we believed it was reasonably possible that we could incur future liabilities (either future court costs or settlements) to resolve the fire litigation lawsuits; however, we could not reasonably estimate the amount of future liabilities. Accordingly, we did not modify the $6 million balance recorded as a liability under deferred litigation credit presented on our consolidated balance sheet.
In our Form 10-Q for the quarterly period ended December 31, 2008, we disclosed in “Note 13. Commitment and Contingencies” that all lawsuits have been settled, except for two remaining suits, one of which is being appealed by the plaintiffs after the trial court entered summary judgment in our favor. Our financial statements for the quarterly period ended December 31, 2008 include accruals for potential expenses associated with these two remaining suits, and the amount of cash for one suit which agreed to a settlement that was not paid at December 31, 2008. We further disclosed that based on our knowledge and judgment of the facts as of December 31, 2008, we believe our financial statements fairly reflect the effect of anticipated ultimate costs to resolve these matters as of December 31, 2008.
For future Form 10-K and Form 10-Q filings, we propose to include expanded disclosure regarding probable, reasonably possible and remote potential expenses depending on the future circumstances similar in concept to the following “underlined and strike-out” disclosure, which for illustrative purposes has been added to the disclosure set forth on page 18 of the Form 10-Q dated September 30, 2008:
Due to the inherent risk of litigation, the ultimate outcome of these cases and any jury trial is uncertain and unpredictable (see “Part II, Item 1A – Risk Factors – Risks Related to Our Business – We are subject to several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas which may have an adverse impact on us”) . At this time, Cano management believes that the lawsuits are without merit and will continue to vigorously defend itself and its subsidiaries, while seeking solutions to resolve these lawsuits in a cost-effective manner. We believe it is reasonably possible that we could incur future liabilities (either future court costs or settlements) to resolve the fire litigation lawsuits; however, we cannot reasonably estimate the amount of future liabilities.
5. We note your response to our prior comment nine. Please confirm that in future filings you will disclose the value of the accelerated vesting of a director’s stock options upon his or her resignation from your board of directors as required by Item 402(k)(2)(vii)(D)(1) of Regulation S-K.
Response: In future filings, we will disclose the value of the accelerated vesting of a director’s stock options upon his or her resignation from our board of directors as required by Item 402(k)(2)(vii)(D)(1) of Regulation S-K.
6. We note your response to prior comment 11, and continue to believe presentation of pro forma statements on the face of your financial statements is not appropriate. Please discontinue presenting such pro forma statements in this manner in future filings. Please contact us at the numbers at the end of this letter to discuss.
Response: We will discontinue presenting pro forma statements on the face of the financial statements in future filings.
7. We have reviewed your response to our prior comment 15 of our letter dated December 23, 2008. Please address each of the following:
● Remove the mitigating language from your proposed risk factor language.
● Please explain what you mean by “(production life)” after the word “responses” in your proposed language.
Response: We will remove the mitigating language from the proposed risk factor and remove the term “production life” as shown below. For our next Form 10-Q filing, we propose to include the following risk factor:
Currently, our lease operating expense per BOE is high in comparison to the oil and natural gas industry as a whole.
Until such time as we achieve production growth from our waterfloods, our lease operating expense per BOE should remain higher than standard for our industry as a whole. The majority of our properties are in the late stage of the primary PDP production life-cycle. With over 1,200 active wells, we are averaging approximately 1 BOEPD per active well. This level of LOE ($36.08 per barrel in fiscal year 2008) is typical of the industry for this type of late-stage PDP production profile. Additionally, as most of our expenses are fixed, LOE per BOEPD will remain high until such time as responses (production life) occur from our existing secondary waterflood projects and tertiary ASP projects. These higher operating costs have an adverse effect on our results of operation.
8. We have reviewed your response to our prior comment 17. We continue to believe that Rule 4-10(a) of Regulation S-X only allows waterflood reserves to be classified as proved developed when a response is actually exhibited in those reserves. This means that if only a portion of the field’s reserves are experiencing a response then you can only classify that portion of the reserves as proved developed. The reserves in the rest of the field, which is not experiencing response, must continue to be classified as proved undeveloped even though the development capital may have already been expended. You can not use a comparison to responses seen in similar fields to help make this determination. Please modify your disclosure or explain to us why it is not needed.
Response: As noted in the March 2, 2009 letter to the Company from our third party reserve petroleum engineer (Miller and Lents, Ltd.) attached hereto, all of the 1.37 MMBOE of PUD reserves that were reclassified to the PDP category for the Panhandle Field, were specifically attributable to the Cockrell Ranch Unit waterflood within the greater Panhandle Field (Note: 1.4 MMBOE was the rounded number reported in our public filings, but the exact number is 1.37 MMBOE). The 1.37 MMBOE that were converted represented only 30% of the PUD reserves estimated for the Cockrell Ranch Unit. Our greater Panhandle Field floodable acreage is approximately 9,000 acres, and the Cockrell Ranch Unit is 1,500 contiguous acres that include a fully-installed, five-spot patterned waterflood of the Brown Dolomite. The Cockrell Ranch Unit waterflood was reactivated in three phases, with the last phase completed in September 2007. The unit is fully developed and includes 71 producers and 59 injectors, with all water handling facilities. The production response confirming the increased reserves recovery due to the installed program was realized by the end of February 2008 when the base rate of 25 barrels of oil per day began increasing. Miller and Lents, Ltd. explained in its reserve report, received by the Company in July 2008 that it had reviewed the Cockrell Ranch Unit waterflood for its reserve report and the oil rate had increased, typical of water injection response, to 80 barrels of oil per day. Although production at the greater Panhandle Field is declining, Miller and Lents concluded that the positive results in the Cockrell Ranch Unit waterflood confirmed that increased recovery will be achieved and was sufficient to reclassify a portion of the reserves relating to the Cockrell Ranch Unit waterflood to the proved producing category.
9. We have reviewed your response to our prior comment 25. We continue to believe that reserves must be calculated based on the actual costs at the end of the year. If at some time in the future costs change, then at that time when you make a reserve determination you may use those revised costs but it is not appropriate to use expected costs as the basis for your current reserve determination. Please modify your document accordingly and refer to Rule 4-10(a) of Regulation S-X.
Response: As noted in the March 2, 2009 letter to the Company from Miller and Lents attached hereto, the costs that Miller and Lents used in the reserve report were based on actual costs effective June 30, 2008, and these costs were held constant through the life of all properties evaluated. The actual costs included a fixed dollar per month per case, plus variable costs of $8.90 per barrel of oil and $1.48 per Mcf of natural gas. None of the fixed or variable costs values were reduced during the life of the properties pursuant to Regulation S-X Rule 4-10(a). The June 30, 2008 production costs, which includes both fixed and variable production costs, divided by 2008 production rates equals $36.08 per barrel.
The future production cost of $23.52 per barrel was determined using the June 30, 2008 costs described above divided by forecasted future higher production rate in barrel of oil equivalent. The total cost per barrel of oil produced is reduced in the future because the fixed cost represents the largest portion of total costs to operate a waterflood. As oil production increases, the total costs to operate the field do not increase proportionately. Therefore, the calculated future total cost (fixed and variable) per barrel of oil produced is reduced.
10. We have reviewed your response to our prior comment 26. You state that the increase in proved reserves was due to an increase in original oil in place and an infill drilling program. We continue to believe that an infill drilling program would only accelerate the recovery of proved reserves in a waterflood, as the drainage areas for the infill wells would have been included in the estimated recovery factor applied to the original oil in place. If the increase in proved reserves is because of an increase in the estimate of original oil in place as you state, this would mean that the original oil in place would have to increase by approximately 60 million barrels of oil. As this was previously a well developed field with many well bores as data points and much production history, please explain to us how the original oil in place could have increased by this amount. Alternatively, please modify your reserve estimate.
Response: The original comment 26 requested a reconciliation of the increase in reserves of 4.8 MMBOE from the Panhandle waterflood and the Cato field with the November 10, 2006 Forrest A. Garb & Associates letter regarding a certain percentage of original oil in place being assumed for proved reserves for the leases in the Panhandle Field. As noted in the previous response letter, 0.2 MMBOE of the increase in reserves was from the Panhandle Field and was due to price increases and 4.3 MMBOE of the increase in reserves was from the Cato Field and was due to increase in original oil in place estimates and PUD reserves and an infill drilling program.
As noted in the March 2, 2009 letter to the Company from Miller and Lents attached hereto, the Cato San Andres Unit was developed on 40-acre spacing and has never been waterflooded although three positive pilots exist within the outline of the Cato San Andres Unit.
We worked with a separate third party reserve engineer (H.J. Gruy and Associates, Inc.) to complete a geological and waterflood study of the Cato San Andres Unit. This geological and waterflood study generated a new model for San Andres P1, P2 and P3 zones which was used in estimating an original oil in place volume of 98 million barrels. In October 2001, United Heritage Corporation estimated an original oil in place volume of 94.8 million barrels. Based on this study, the estimated original oil in place volume was increased.
We have begun drilling infill wells with the plan to implement a waterflood on 20-acre spacing. As part of the Gruy study referenced above, statistics were compiled for San Andres formation waterfloods in West Texas and Southeast New Mexico. The analysis of 79 patterned San Andres waterfloods in the Permian Basin indicate that 40-acre spacing waterfloods had an average secondary to primary ratio of .67 versus the average secondary to primary ratio of .83 for 20-acre spacing. Based on the review by Miller and Lents of these secondary to primary ratios, verification by Miller and Lents of the updated geologic model and the results of recent infill drilling, Miller and Lents applied a .83 secondary to primary ratio to specific areas within the Cato San Andres Unit to be developed on 20-acre spacing. This was the primary reason for the increase in the Cato Field reserves compared to prior years when a secondary to primary ratio of .67 was used.
Please let me know if the responses are acceptable. 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
MILLER AND LENTS, LTD.
INTERNATIONAL OIL AND GAS CONSULTANTS
FOUNDED 1948
March 2, 2009
Mr. Patrick McKinney
Cano Petroleum, Inc.
Burnett Plaza
801 Cherry Street, Unit 25, Suite 3200
Forth Worth, Texas 76102
Re: Cano Petroleum, Inc.
SEC Comments
Dear Mr. McKinney:
In response to the letter dated February 20, 2009, from the United Sates Securities and Exchange Commission (SEC) to Cano Petroleum, Inc. (Cano) concerning Cano’s Form 10-K for the fiscal year ended June 30, 2008 filed September 11, 2008, and the Amendment No. 1 to form 10-K for the fiscal year ended June 30, 2008 filed October 28, 2008, Miller and Lents, Ltd. (MLL) submits the following comments. These address Engineering Comments 8, 9, and 10.
Engineering Comment 8, a result of Cano’s response to the original SEC Comment 17, pertains to the movement of 1.4 million barrels equivalent of proved undeveloped reserves to proved developed reserves because of the positive response to the waterflood. To clarify Cano’s initial response, it should be noted that the 1.37 million barrels equivalent reserve class movement is specifically attributable to the Cockrell Ranch Unit waterflood within the greater Panhandle Field. Cano’s greater Panhandle Field floodable acreage is approximately 9,000 acres. The Cockrell Ranch Unit is 1,500 contiguous acres that include a fully-installed, five-spot patterned waterflood of the Brown Dolomite. The waterflood was reactivated in three phases, with the last phase completed in September 2007. The unit is fully developed and includes 71 producers and 59 injectors, with all water handling facilities. Water injection began in 2006, increasing to its current rate of 50,000 barrels of water injection per day. The production response confirming the increased reserves recovery due to the installed program was realized at the end of February 2008 when the base rate of 25 barrels of oil per day began increasing. By June 2008, when MLL reviewed this waterflood for its reserve report, the oil rate had increased, typical of water injection response, to 80 barrels of oil per day. Although production in the greater Panhandle Field is declining, we concluded the positive response in the Cockrell Ranch Unit confirmed that increased recovery will be achieved and was sufficient to move part of these reserves to the proved producing category. The 1.37 million barrels equivalent converted represented only 30 percent of the PUD reserves estimated for the Cockrell Ranch Unit.
Engineering Comment 9, a result of Cano’s response to the original SEC Comment 25, pertains to reserves being calculated based on the actual costs at the end of the year. We have confirmed that costs used in our year-end June 30, 2008 reserves report were based on actual costs effective June 30, 2008 and were held constant through the life of all properties evaluated. The costs included a fixed $ per month per case, plus $8.90 per BO and $1.48 per Mcf variable cost. None of the fixed or variable cost values were reduced during the life of the properties pursuant to Regulation S-X Rule 4-10(a). The misunderstanding is that Cano is quoting cost per producing barrel oil equivalent. The 2008 actual total production cost of $36.08 per barrel, which includes both fixed and variable costs production costs, were determined using the June 30, 2008 costs stated above divided by 2008 production rates in barrel oil equivalent. The future production cost of $23.52 per barrel was determined using the June 30, 2008 costs stated above divided by a forecasted future higher producing rate in barrel oil equivalent. The total cost per barrel of oil produced is reduced in the future because the fixed cost represents the largest portion of the total costs to operate a waterflood. As oil production increases, the total costs to operate the field do not increase proportionally. Therefore, the calculated total cost (fixed and variable) per barrel of oil produced is reduced. We assume Cano’s intent for quoting these two cost figures was to demonstrate that, as the production increases, the cost per producing barrel would decrease.
Engineering Comment 10, a result of Cano’s response to the original SEC Comment 26, pertains to the increase in proved reserves due to an increase in original oil in place and an infill drilling program. In the Cano response dated January 21, 2009, you stated that “4.3 MMBOE was a result of adding Proved Reserves from Cato Field due to increases in original oil in place estimates and PUD reserves and an infill drilling program”. To help clarify your statement, two things should be noted: (1) The Cato San Andres Unit was developed on 40-acre spacing and has never been water flooded although three positive pilots exist within the Unit outline and (2) in January 2008, Cano, along with H.J. Gruy and Associates, Inc. (Gruy), completed a geological and engineering waterflood study of the Cato San Andres Unit. In this study, a new geologic model for the San Andres P1, P2, and P3 zones was generated and used in estimating an original oil-in-place volume (OOIP) of 98 million barrels. In October, 2001, United Heritage Corporation estimates of OOIP was of 94.8 million barrels. This is the basis for the original statement regarding an increase in OOIP. Cano has begun drilling infill wells with the plan to implement a waterflood on 20-acre spacing. As part of the above Gruy study, statistics were compiled for San Andres formation waterfloods in West Texas and Southeast New Mexico. The analysis of 79 patterned San Andres waterfloods in the Permian Basin indicated a clear difference in recovery between development on 40- and 20-acre spacing. Specifically, 40 acres spacing water floods had an average secondary to primary ratio (S/P) of .67 versus the average S/P of .83 for 20 acres spacing. Based on our review of these statistics, verification of the updated geologic model and the results of recent infill drilling, we applied a .83 S/P to specific areas within the unit to be developed on 20-acre spacing. This was the primary reason for the increased in Cato Field reserves compared to over prior years when a S/P of .67 was used.
If you have questions, require additional information or need clarification on any of our comments, please do not hesitate to contact us.
| | Very Truly Yours, | |
| | | |
| | MILLER AND LENTS, LTD. | |
| | | | |
| | | /s/ Carl D. Richard | |
| | | Carl D. Richard, P. E. | |
| | | Vice President | |
| | | | |
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