[Haynes and Boone, LLP Letterhead]
December 15, 2006
Via Facsimile 202-772-9368
and Via EDGAR
Ms. Carmen Moncada-Terry
Mr. James Murphy
Division of Corporation Finance
United States Securities and Exchange Commission
100 F St., N.E.
Washington, D.C. 20549
Re: Cano Petroleum, Inc.
Registration Statement on Form S-1
Filed October 13, 2006
File No. 333-138003
Form 10-K, for Fiscal Year ended June 30, 2006
Filed September 25, 2006
File No. 001-32496
Dear Ms. Moncada-Terry and Mr. Murphy:
On behalf of Cano Petroleum, Inc. (the “Company”), we are submitting a draft for your review of the Company’s responses to the engineering comments to the Company’s Form S-1 filed on October 13, 2006 (the “Form S-1) and the Company’s Form 10-KSB for the fiscal year-ended June 30, 2006 (the “Form 10-KSB”) set forth in the letter from the Securities and Exchange Commission (“SEC”) dated November 9, 2006. Please be advised that separately we have responded to the accounting comments to the Form S-1 and Form 10-KSB set forth in the same letter.
The staff’s comments are set forth below and the Company’s responses are set forth after the staff’s comments.
9. Please provide the technical study performed by Forest A. Garb & Associates to support your classification of the secondary recovery reserves as proved undeveloped for the W.O. Energy and the Pantwist acquisitions in the Panhandle field.
Response: The Company has provided to Mr. James Murphy various information in support of the classification of the secondary recovery reserves as proved undeveloped for the W.O. Energy and the Pantwist acquisitions in the Panhandle field, including the November 10, 2006 letter from Forrest A. Garb & Associates, Inc. attached hereto.
10. You state that for the Panhandle field you intend to implement a pilot water-flood project and if the pilot project proves successful you intend to expand the water-flood operation to the entire field. It appears that you have not made an investment decision to develop the entire field with a water-flood. We also note that it appears that you have not secured the necessary water rights. Please explain, in detail, why you believe it is appropriate to classify the water-flood reserves over the entire field as proved reserves at this time.
Response: See the November 10, 2006 letter from Forrest A. Garb & Associates referenced in response to No. 9 regarding the justification for the Company recognizing proved undeveloped reserves for the Panhandle Field. On October 25, 2006, the Company provided its reserve report, prepared by Forrest A. Garb & Associates dated as of July 1, 2006 to Mr. James Murphy. The reserve report estimates that it will require a $119,345,000 net investment to fully develop the entire Panhandle Field’s undeveloped reserves. For the fiscal year ending June 30, 2007, the Company intends to spend $27.3 million of its total capital budget of $41 million instituting Phase I of the waterflood project at the Panhandle Field. This waterflood project was inadvertently identified as a pilot waterflood project in the Form 10-KSB and Form S-1. The $27.3 million projected expenditure represents 67% of the Company’s total fiscal year capital budget. As the waterflood provides additional production, the waterflood will lead to proved undeveloped reserves becoming proved producing reserves. The additional production should generate additional cash flow and the increase in proved producing reserves is expected to result in a greater borrowing base with our lender which should provide the necessary capital resources to fully develop the waterflood of the entire Panhandle Field. The Company currently maintains water rights and sources associated with its leasehold position sufficient for the implementation of Phase I of the waterflood, has ready access to other sources of water and is currently in the process of securing additional water supplies on attractive terms (which additional water supplies were used in the prior successful analog waterfloods and which have been previously approved for such use by the state regulatory authority). Attached are blacklines of “Management’s Discussion and Analysis — Proved Reserves” from the Form 10-KSB and “Prospectus Summary — Our Properties,” “Business and Properties — Our Properties,” “Business and Properties — Present Activities,” “Business and Properties — Present Activities” and “Management’s
2
Discussion and Analysis of Financial Condition and Results of Operations — Our Properties” from the Form S-1 reflecting the proposed changes to reflect that the Company is instituting Phase I of the waterflood project at the Panhandle Field rather than a pilot waterflood project as was inadvertently disclosed in the Form 10-KSB and Form S-1.
11. We note that you had 16.4 BCF of negative revisions of past estimates at June 30, 2006. You indicate that 7.2 BCF of the revision is due to a gas contract that was not finalized. Please explain in detail why it was appropriate to classify the 7.2 BCF related to a gas contract as proved in 2005. We also note that the 16.4 BCF negative revision is larger than the entire volume of reserves that you had booked as proved in 2005. Please also clarify this for us.
Response: See the attached November 29, 2006 letter from Forrest A. Garb & Associates, Inc. regarding the revision of gas reserves and other revisions from July 1, 2005 to July 1, 2006.
12. Please revise your document to present separate line items for your future production costs and future development costs. See SFAS 69 paragraph 30b for guidance. Confirm to us that you will continue this presentation in future filings for as long as future development costs are significant.
Response: Attached are blacklines of the “Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited) — Standardized Measure of Discounted Future Cash Flows” for the Form 10-KSB and the Form S-1 reflecting the proposed revisions by separately stating “Future production costs” and “Future development costs.” The Company will continue this presentation in future filings as long as future development costs are significant.
13. We note that in 2006 you indicate that for your total proved reserves you are forecasting operating costs and taxes of 6,087.7 M$ on production estimates of 396,400 barrels equivalent. Reconcile this with the fact that in 2005 you produced 309,200 barrels equivalent in 2005 with production costs and taxes of 8,160.9 M$.
Response: See the attached November 10, 2006 letter from Forrest A. Garb & Associates, Inc. regarding the reduction in operating costs from 2005 to 2006.
3
Enclosed herewith is a statement from the Company regarding (i) the responsibility of the Company for the adequacy and accuracy of the disclosure in the filings, (ii) the fact that the staff’s comments or changes in response to staff comments do not foreclosure the SEC for taking any action with respect to the filing; and (iii) the fact that the Company may not assert staff comments as a defense in any proceeding initiated by the SEC or any person under the federal securities laws of the United States.
Please let me know if the proposed responses are acceptable so that we can prepare and file Amendment No. 1 to the Form S-1 and the Form 10-KSB/A. 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: James K. Teringo, Jr.
4
FORREST A. GARB & ASSOCIATES, INC.
INTERNATIONAL PETROLEUM CONSULTANTS
5310 HARVEST HILL ROAD, SUITE 275, LB 152
DALLAS, TEXAS 75230 - 5805
(972)788-1110 Telefax (972)991-3160 (E MAIL) forgarb@forgarb.com
November 10, 2006
Mr. Patrick McKinney
Cano Petroleum, Inc.
Burnett Plaza
801 Cherry Street, Unit 25, Suite 3200
Fort Worth, Texas 76102
Re: Panhandle Waterflood Reserves
Dear Mr. McKinney:
In response to the letter dated November 9, 2006, from the United States Securities and Exchange Commission (SEC) to Cano Petroleum, Inc. (Cano) concerning Cano’s registration statement filed on October 13, 2006, Forrest A. Garb & Associates, Inc. (FGA) submits the following comments. These comments only address item nine of this letter relating to the Panhandle waterflood reserves.
With Cano’s acquisition of certain Panhandle field reserves, referenced in the SEC letter as W.O. Energy and Pantwist, FGA studied the proved undeveloped reserves that could be attributed to a waterflood program. The primary points of interest in this study are:
1) Waterflood proved undeveloped reserves were based on the successful waterflood program in the Schafer Ranch East lease of the Panhandle field. Parameters such as response time, production increase, and decline were based on the historic performance of this waterflood.
2) Only those leases in the Panhandle field and in the same trend as the Schafer Ranch East were considered in the study.
3) Sources from other published waterflood projects/pilots in the Panhandle field were also referenced. In addition to the Schafer Ranch East waterflood, other waterflood projects were reviewed in the Morse, Stansberry, and South Pampa areas of the Panhandle field. A review of these waterfloods indicate a secondary recovery ranging from 6.5% to 11% of original oil in place (OOIP), with an average of 8.3% of OOIP recovery.
4) For the purpose of this study, a 7% of OOIP average recovery was assumed for Cano’s leases.
5) All Cano leases were not handled the same. Factors such as current producing water/oil ratio, gas/oil ratio, and size and location of contiguous acres held. The reserves for leases producing at a higher water/oil ratio were significantly reduced or eliminated. The same approach was applied to those leases producing at high gas/oil ratios. Reserves for leases with higher producing gas/oil ratios were either significantly reduced or eliminated due to possible gas cap development. The reserves for smaller contiguous acreage leases were either eliminated or substantially reduced due to the
difficulty of efficiently setting up injector/producer patterns. Smaller leases were completely eliminated if they were isolated from larger leases because of the cost of expanding the waterflood project to these smaller isolated leases.
6) Once the base incremental waterflood reserves for each lease were established, capital expenditures were assigned to each lease based on the current number of active wellbores. Capital expenditures were assigned for drilling new wells for production and water injection, upgrading fluid capacity, and for the addition of water flood infrastructure and facilities.
7) Water injection rates per injector are assumed to be approximately 500 barrels of water per day from the Schafer Ranch waterflood. The exception to this assumption is in the Cockrell Ranch and Haile leases where core data indicate a more favorable water injection rate capability. The reserves for these leases were not increased; however, the time to recover the incremental waterflood reserves would be less with the higher injection rates.
8) Economics were run on a lease-by-lease basis with operating costs being split between fixed costs and variable costs with the variable costs dependent upon water injection/production. Those leases that fell below the economic limit by taking into account capital investments and lease operating costs were eliminated from the reserve base.
If you have any questions or need clarification on any of these points, please do not hesitate to contact us.
Yours truly,
Forrest A. Garb & Associates, Inc.
2
FORREST A. GARB & ASSOCIATES, INC.
INTERNATIONAL PETROLEUM CONSULTANTS
5310 HARVEST HILL ROAD, SUITE 275, LB 152
DALLAS, TEXAS 75230 - 5805
(972)788-1110 Telefax (972)991-3160 (E MAIL) forgarb@forgarb.com
November 29, 2006
Mr. Patrick McKinney
Cano Petroleum, Inc.
Burnett Plaza
801 Cherry Street, Unit 25, Suite 3200
Fort Worth, Texas 76102
Re: Negative Gas Reserves Revision
Dear Mr. McKinney:
In response to the letter dated November 9, 2006, from the United States Securities and Exchange Commission (SEC) to Cano Petroleum, Inc. (Cano) concerning Cano’s registration statement filed on October 13, 2006, Forrest A. Garb & Associates, Inc. (FGA) submits the following comments. These comments only address item 11 of this letter relating to the negative revision of gas reserves from July 1, 2005, to July 1, 2006.
The 7.2 billion cubic feet (Bcf) of proved gas reserves were included as of July 1, 2005, because Cano was, at that time, producing and was capable of selling the gas through leased processing equipment that removed excess oxygen from the gas, thus allowing it to meet a maximum oxygen content quality specification contained in the then gas contract. By July 1, 2006, Cano had elected not to renew its lease of the equipment and had canceled its gas contract, thus no gas was being sold. As-of July 1, 2006, Cano had a new gas contract; however, a minimum gas quality remained in the contract. The produced gas did not meet the minimum requirements; therefore, the gas could not be included as proved reserves. As-of July 1, 2006, Cano planned recompletions to the Duffer gas zone to improve the overall gas quality in the field, but the reserves associated with the Duffer gas zone could not be considered proved by July 1, 2006.
The remainder of the 16.4 Bcf of negative revision can be attributed to gas production from the Panhandle field. As the Panhandle field was acquired after the July 1, 2005 reporting period, it was not included in the July 1, 2005 report; however, reserves were determined at the time of acquisition. The gas reserves reported at the time of acquisition decreased from the time of acquisition to July 1, 2006, primarily due to a significantly lower gas price used for the latter reserves determination at July 1, 2006.
This letter is submitted in place of our letter dated November 13, 2006. If you have any questions or need clarification on any of these points, please do not hesitate to contact us.
Yours truly,
Forrest A. Garb & Associates, Inc.
FORREST A. GARB & ASSOCIATES, INC.
INTERNATIONAL PETROLEUM CONSULTANTS
5310 HARVEST HILL ROAD, SUITE 275, LB 152
DALLAS, TEXAS 75230 - 5805
(972)788-1110 Telefax (972)991-3160 (E MAIL) forgarb@forgarb.com
November 10, 2006
Mr. Patrick McKinney
Cano Petroleum, Inc.
Burnett Plaza
801 Cherry Street, Unit 25, Suite 3200
Fort Worth, Texas 76102
Re: Operating Cost Reduction
Dear Mr. McKinney:
In response to the letter dated November 9, 2006, from the United States Securities and Exchange Commission (SEC) to Cano Petroleum, Inc. (Cano) concerning Cano’s registration statement filed on October 13, 2006, Forrest A. Garb & Associates, Inc. (FGA) submits the following comments. These comments only address item 13 of this letter relating to the reduction in operating costs.
There is a decrease in operating expenses reported from 2005 to 2006. Several of the major properties were purchased by Cano in 2005, and reserve evaluations were conducted by FGA at the time of acquisition. For these evaluations, lease operating expenses were assumed to be equal to those of the prior operator. Possible cost efficiencies that Cano could leverage for these acquisitions had not been proven to be realized; therefore, were not considered in the 2005 evaluations. By July 1, 2006, there had been sufficient time under the Cano operating structure to quantify the increased efficiencies, and were therefore included in the 2006 evaluation.
If you have any questions or need clarification on this point, please do not hesitate to contact us.
Yours truly,
Forrest A. Garb & Associates, Inc.
· Acquisition of Pantwist properties for $23.4 million (Note 3).
· Purchase of an additional 10.5% revenue interest in the Davenport field for $0.7 million (Note 7).
· Capital expenditures of $5.7 million, consisting primarily of surfactant-polymer developmental activities, returning non-producing wells to production and implementing environmental safeguards to our existing fields.
As of June 30, 2006, our common stock was the only class of stock outstanding. As discussed in Note 13, on September 6, 2006, we completed equity issuances of the Series D Convertible Preferred Stock and common stock.
Proved Reserves
Based on reserve reports prepared by Forrest A. Garb & Associates, Inc., independent petroleum engineers dated July 1, 2006, our total reserves are summarized as follows:
|
|
|
| Rich |
|
|
|
|
|
|
| Panhandle |
|
|
|
|
|
|
| Nowata |
| Valley |
| Davenport |
| Desdemona |
| Corsicana |
| (WO Energy) |
| Pantwist |
| Total |
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil - Mbbls |
| 1,266 |
| 226 |
| 1,561 |
| 625 |
| 848 |
| 24,550 |
| 4,792 |
| 33,868 |
|
Gas - Mmcf |
| 232 |
| 2,260 |
| 157 |
| — |
| — |
| 52,845 |
| 13,608 |
| 69,102 |
|
Proved Barrels of Equivalent Oil (“MBOE”) |
| 1,305 |
| 602 |
| 1,587 |
| 625 |
| 848 |
| 33,358 |
| 7,060 |
| 45,385 |
|
Proved Producing |
| 1,305 |
| 602 |
| 423 |
| 234 |
| — |
| 4,673 |
| 2,113 |
| 9,350 |
|
Our proved reserves equate to 45,385 MBOE of proved reserves, consisting of (21%) or 9,350 MBOE of proved producing reserves, 1,555 MBOE (3%) of proved non-producing reserves and 34,480 MBOE (76%) of proved undeveloped reserves.
Regarding our proved undeveloped reserves, approximately eighty-three percent (83%), or 28,685 MBOE, are attributable to a Panhandle Field waterflood implementation. Approximately three percent (3%), or 848 MBOE, are attributable to a surfactant-polymer application in the Corsicana Field and fourteen percent (14%), or 4,947 MBOE, are attributable to waterflood implementation for the Pantwist properties. The waterflood implementations for the Panhandle Field and the Pantwist properties, and the waterflood and surfactant-polymer application to the Corsicana Field involve significant capital investment and an extended period of time from the first investment until actual production occurs. Generally, the surfactant-polymer is regarded as more risky as compared to waterflooding; however, the Corsicana Field has been the subject of a successful polymer pilot and we believe conditions for surfactant polymer-flooding are favorable for this field. Our ability to recover and successfully convert proved undeveloped reserves to proved producing reserves is greatly contingent upon our ability in the future to obtain additional financing and/or raise additional capital, and further, greatly contingent upon inherent uncertainties associated with the success of producing crude oil and natural gas from our developmental activities, and volatile crude oil and natural gas prices.
Reserves were estimated using crude oil and natural gas prices and production and development costs in effect on July 1, 2006. On July 1, 2006, the crude oil and natural gas prices were $73.94 per barrel and $5.83 per MMbtu, respectively. The values reported may not necessarily reflect the fair market value of the reserves.
Capital Spending Plan for Fiscal Year 2007
Our capital spending plan for the twelve months ended June 30, 2007, excluding potential acquisitions, is projected to be $41 million to implement developmental projects at our existing fields to increase reserves and production as follows:
Panhandle Field. We intend to implement Phase I of full-field waterflood injection operations. This will involve drilling six new wells, converting 25 existing wells to water injection, securing water rights, and designing new facilities. We expect to see increased production during the quarter ending June 30, 2007.
Desdemona Field. We intend to implement a waterflood injection operation to the entire field. This will involve drilling six new wells, converting existing wells to water injection, securing water rights, and designing new facilities. We expect to see increased production during the quarter ending June 30, 2007. We also intend to drill ten natural gas wells into the Marble Falls formation, which is above the Barnett Shale. We are evaluating our options regarding our Barnett Shale mineral rights.
Corsicana Field. This field has had a proven surfactant-polymer chemical injection pilot. We intend to re-implement a prior waterflood injection operation to the entire field. This will involve drilling sixteen new wells, converting existing wells to water injection, securing water rights, and designing new facilities. We expect to see increased production during the quarter ending March 31, 2007. We intend to implement a surfactant-polymer chemical injection during the quarter ending June 30, 2007.
Nowata Field. This field is currently being waterflooded. We intend to implement a surfactant-polymer chemical injection pilot project during the quarter ended December 31, 2006. We expect to see a production response during the quarter ending December 31, 2007.
Davenport Field. This field is currently being waterflooded. We intend to workover and bring existing non-producing wells to production. We are also evaluating this field for surfactant-polymer injection. This evaluation, coupled with the knowledge gained from the Corsicana and Nowata fields, is expected to enhance its value as a surfactant-polymer candidate.
Based on our current cash resources and other current assets, management believes we have sufficient liquidity to fund operations for the next twelve months.
Results of Operations
Overall
For the twelve months ended June 30, 2006 (“2006 Fiscal Year”), we had a loss applicable to common stock of $1.8 million, which is $1.6 million lower as compared to the $3.4 million loss applicable to common stock incurred for the twelve months ended June 30, 2005 (“2005 Fiscal Year”).
The following table summarizes the differences between the two fiscal years.
| Fiscal Year Ended |
|
|
| ||||||
|
| June 30, |
| Increase |
| |||||
Amounts in $millions |
| 2006 |
| 2005 |
| (Decrease) |
| |||
Results of oil and gas producing operations excluding hedging loss |
| $ | 8.5 |
| $ | 2.0 |
| $ | 6.5 |
|
Less the following items: |
|
|
|
|
|
|
| |||
General and administrative expenses |
| 7.2 |
| 3.0 |
| 4.2 |
| |||
Interest expense, net |
| 2.5 |
| — |
| 2.5 |
| |||
Deferred compensation expense |
| 0.6 |
| 1.8 |
| (1.2 | ) | |||
Deferred income tax benefit |
| (3.5 | ) | — |
| (3.5 | ) | |||
Preferred stock discount |
| — |
| 0.4 |
| (0.4 | ) | |||
Loss on hedge contracts |
| 3.2 |
| — |
| 3.2 |
| |||
Other |
| 0.3 |
| 0.2 |
| 0.1 |
| |||
Net loss |
| $ | (1.8 | ) | $ | (3.4 | ) | $ | 1.6 |
|
Pantwist Properties. Effective February 1, 2006, our wholly-owned subsidiary, Pantwist LLC, acquired additional properties, including 167 wells and 2 workover rigs and covering approximately 9,700 acres in the Panhandle field (the “Pantwist Properties”) for a cash purchase price of $24 million. Proved reserves as of July 1, 2006 attributable to the Pantwist Properties are 7,060 MBOE, of which 4,947 MBOE are proved undeveloped and none of which are proved non-producing. Current production is approximately 400 BOEPD. We anticipate implementation of waterflood injection operations with respect to the Pantwist Properties in the 2008-2009 timeframe.
We are in the process of implementing a development program on our properties to further develop proved undeveloped reserves and to increase our reserve base. To date, we have conducted limited development operations on our properties. These operations have involved laboratory testing to evaluate EOR opportunities, design and initial construction of pilot area facilities, and some developmental drilling, including core evaluations, reservoir simulation studies and other development studies and evaluations.
For the fiscal year ended June 30, 2007 we have a capital budget of $41 million. The bulk of the capital budget, approximately 67%, or $27.3 million, is allocated to waterflood development in the Panhandle Properties. Approximately 14%, or $5.8 million, is allocated to waterflood development in the Corsicana and Desdemona Properties. Approximately 8%, or $3.2 million, is allocated to surfactant polymer pilot programs at the Nowata and Davenport Properties. Approximately $4.5 million, or 11%, is targeted to drill a ten-well Marble Falls/Barnett Shale test program at the Desdemona Properties.
Waterflood operations and EOR techniques such as surfactant-polymer chemical injection involve significant capital investment and an extended period of time, generally a year or longer, from the initial pilot program until increased production occurs. Generally, surfactant polymer injection is regarded as more risky compared to waterflood operations. Our ability to successfully convert proved undeveloped reserves to proved producing reserves will be contingent upon our ability to obtain future financing and/or raise additional capital, and further, is greatly contingent upon inherent uncertainties associated with the production of oil and natural gas as well as price volatility. See “Risk Factors.”
We believe significant acquisition opportunities will continue to exist primarily because the major energy companies and large independents continue to focus their attention and resources toward the discovery and development of large fields. During the past several years, the major companies have been divesting themselves of their mature oilfields, a trend management expects will continue. Also, the recent economics of the oil and natural gas market have improved as prices have risen substantially. These conditions provide ample opportunities for smaller independent companies to acquire and exploit mature U.S. fields. We expect that there will be increased competition for such properties in the future.
· Acquire Strategic Assets. We seek to acquire low-cost assets with a high ratio of non-proven or proved undeveloped reserves suitable for waterflood and EOR techniques, primarily in the onshore United States. We believe we have acquired an attractive portfolio of assets to implement our business plan. We will continue to selectively target potential acquisition candidates in a disciplined manner, which involves being financially prudent and acquiring assets that meet our engineering and operational standards. We focus on U.S. operations. Accordingly, we are not subject to geopolitical uncertainties, dependence on foreign sources and other issues related to overseas operations.
June 30, 2007. If there is a successful waterflood response, it is anticipated that a Surfactant Polymer Pilot will be initiated in the field. We have allocated additional funds from the Fiscal Year 2007 capital budget to drill 10 vertical tests penetrating the Marble Falls and/or Barnett Shale in the Desdemona Properties. Drilling is expected to begin during the quarter ended December 31, 2006.
Corsicana Properties. During 2005, we began acquiring oil and natural gas leases comprising the Corsicana Properties. Currently, we have a 100% working interest in 341 acres under lease and no current production from these properties. The Corsicana Properties were the subject of a proved surfactant-polymer chemical injection pilot in the 1980s and contain proved reserves as of July 1, 2006 of 848 MBOE, all of which are proved undeveloped. Our Fiscal Year 2007 capital budget contemplates re-implementation of a prior waterflood. 16 new wells are planed to be drilled by December 31, 2006 in this reservoir (which contained 7 MMBOE of original oil in place) to develop an effective sweep pattern and re-energize the formation. We have the required drilling rig under contract and expect facilities installation and well re-works to be complete by mid-January 2007 to start water injection. A surfactant polymer injection application is anticipated once the waterflood reimplementation is complete.
Panhandle Properties. On November 29, 2005, through our acquisition of W.O. Energy of Nevada, Inc. for an adjusted cash price of $48.4 million and 1,791,320 shares of common stock with an aggregate value of approximately $8.24 million, we acquired inventory, 10 workover rigs and related equipment, 480 producing wells, 40 water disposal wells and 380 idle wells on approximately 20,000 acres in Carson, Gray and Hutchinson Counties, Texas. Proved reserves as of July 1, 2006 attributable to the Panhandle Properties are 33,358 MBOE, of which 28,685 MBOE are proved undeveloped and none of which is proved non-producing. Current production is approximately 800 BOEPD. This asset in the Brown Dolomite formation contained over 382 MMBOE of original oil in place and is surrounded by successful waterflood analogs, with the Panhandle Properties having never been subject to any form of secondary recovery. Included in our Fiscal Year 2007 capital budget is an initial Phase I development at the 1,500 acre Cockrell Ranch Unit which will include expenditures of approximately $6 million and in anticipated to commence prior to December 31, 2006. Phase I development will be comprised of installation of injection facilities, drilling of 6 new wells and conversion of 25 existing producers to injection. The Phase I development will be executed with one contract drilling rig, and 5 workover rigs that are owned by our wholly-owned subsidiary W.O. Operating Company, Ltd. Phase II and Phase III development of the Cockrell Ranch Unit is anticipated to include the re-drilling of 29 additional wells and the conversion of 45 existing producers to injection. In total, the Cockrell Ranch Unit development is anticipated to have 72 injection wells and 64 producers. Phase I injection is anticipated to commence by February 2007 with preliminary production response anticipated by May 2007. Full waterflood development over the remaining 11,000+ net acres of the Panhandle Properties is anticipated once the initial response data is available.
Pantwist Properties. Effective February 1, 2006, our wholly-owned subsidiary, Pantwist LLC, acquired additional properties, including 167 wells and 2 workover rigs and covering approximately 9,700 acres in the Panhandle field for a cash purchase price of $24 million. Proved reserves as of July 1, 2006 attributable to the Pantwist Properties are 7,060 MBOE, of which 4,947 MBOE are proved undeveloped and none of which are proved non-producing. Current production is approximately 400 BOEPD. We anticipate implementation of waterflood injection operations with respect to the Pantwist Properties in the 2008-2009 timeframe.
We are in the process of implementing a development program on our properties to further develop proved undeveloped reserves and to increase our reserve base. To date, we have conducted limited development operations on our properties. These operations have involved laboratory testing to evaluate
Drilling Activity
During the twelve months ended June 30, 2006, we re-entered and deepened one well on our Desdemona Properties. This is the only well drilling activity for that time period.
During the twelve months ended June 30, 2005, we drilled two (gross and net) developmental wells on our Davenport Properties and one (gross and net) well on our Nowata Properties for testing of surfactant polymer technology. During the twelve months ended June 30, 2004, we did not have any drilling activity.
Present Activities
During our first two years of operations, our primary focus has been to achieve growth through acquiring interests in existing, mature fields in the mid-continent region of Texas and Oklahoma. We believe the portfolio of oil and natural gas properties we have acquired to date provides suitable opportunities to apply EOR techniques. We are in the process of implementing a development program on our properties to further develop proved undeveloped reserves and to increase our reserve base. To date, we have conducted limited development operations on our properties. These operations have involved laboratory testing to evaluate EOR opportunities, design and initial construction of pilot area facilities, and some developmental drilling, including core evaluations, reservoir simulation studies and other development studies and evaluations. For the fiscal year ended June 30, 2007 we have a capital budget of $41 million. See “Planned Development Program” above and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Panhandle Properties. Approximately 67%, or $27.3 million, of the 2007 capital budget is targeted to implement Phase I of a full field waterflood operation on the Panhandle Properties commencing in the quarter ending December 31, 2006. These properties are in the Brown Dolomite formation and are surrounded by successful waterflood analogs. The properties have never been subject to secondary recovery. The budgeted amount is anticipated to convert proved undeveloped reserves into proved developed producing reserves. Initial development expenditures of approximately $6 million will be spent to design and install injection facilities, secure water rights, drill 6 new wells and convert approximate 25 existing wells to water injection. Initial response is currently expected by May 2007.
Corsicana Properties. Approximately $3.2 million, or 8%, of the 2007 capital budget is targeted for reimplementation of a prior waterflood on the Corsicana Properties. We plan to drill 16 new wells by December 2006 in this high quality sandstone reservoir to develop an effective sweep pattern and re-energize the formation. We expect initial response from this waterflood by April 2007. A surfactant polymer or tertiary recovery phase is anticipated once the waterflood re-implementation is complete. A proven surfactant polymer pilot was conducted in the field by a prior owner.
Desdemona Properties. Approximately $2.6 million, or 6%, of our 2007 capital budget is dedicated to initiate waterflood operations on the Desdemona Properties. Initial response is expected to occur by May 2007. Field work, including numerous well re-works, facilities installation and the drilling of 6 new wells, is expected to commence by January 2007. Following a successful waterflood response, we expect to initiate a surfactant polymer pilot. In addition, intend to drill 10 natural gas wells into the Marble Falls formation, which is above the Barnett Shale. We are currently evaluating our options regarding our Barnett Shale mineral rights.
Nowata and Davenport Properties. Waterflood operations were implemented on these fields by previous owners. Approximately $3.2 million, or 8%, of our 2007 capital budget is allocated to prepare surfactant polymer pilots in these two fields. The pilots are expected to be initiated after fiscal year-end June 2007 with expected response by December 2007.
implementation of waterflood injection operations with respect to the Pantwist Properties in the 2008-2009 timeframe.
Planned Development Program
We are in the process of implementing a development program on our properties to further develop proved undeveloped reserves and to increase our reserve base. To date, we have conducted limited development operations on our properties. These operations have involved laboratory testing to evaluate EOR opportunities, design and initial construction of pilot area facilities, and some developmental drilling, including core evaluations, reservoir simulation studies and other development studies and evaluations.
For the fiscal year ended June 30, 2007 we have a capital budget of $41 million. The bulk of the capital budget, approximately 67%, or $27.3 million, is allocated to waterflood development in the Panhandle Properties. Approximately 14%, or $5.8 million, is allocated to waterflood development in the Corsicana and Desdemona Properties. Approximately 8%, or $3.2 million, is allocated to surfactant polymer pilot programs at the Nowata and Davenport Properties. Approximately $4.5 million, or 11%, is targeted to drill a ten-well Marble Falls/Barnett Shale test program at the Desdemona Properties.
Waterflood operations and EOR techniques such as surfactant-polymer chemical injection involve significant capital investment and an extended period of time, generally a year or longer, from the initial pilot program until increased production occurs. Generally, surfactant polymer injection is regarded as more risky compared to waterflood operations. Our ability to successfully convert proved undeveloped reserves to proved producing reserves will be contingent upon our ability to obtain future financing and/or raise additional capital, and further, is greatly contingent upon inherent uncertainties associated with the production of oil and natural gas as well as price volatility. See “Risk Factors.”
Industry Conditions
We believe significant acquisition opportunities will continue to exist primarily because the major energy companies and large independents continue to focus their attention and resources toward the discovery and development of large fields. During the past several years, the major companies have been divesting themselves of their mature oilfields, a trend management expects will continue. Also, the recent economics of the oil and natural gas market have improved as prices have risen substantially. These conditions provide ample opportunities for smaller independent companies to acquire and exploit mature U.S. fields. We expect that there will be increased competition for such properties in the future.
Our Strategy
· Acquire Strategic Assets. We seek to acquire low-cost assets with a high ratio of non-proven or proved undeveloped reserves suitable for waterflood and EOR techniques, primarily in the onshore United States. We believe we have acquired an attractive portfolio of assets to implement our business plan. We will continue to selectively target potential acquisition candidates in a disciplined manner, which involves being financially prudent and acquiring assets that meet our engineering and operational standards. We focus on U.S. operations. Accordingly, we are not subject to geopolitical uncertainties, dependence on foreign sources and other issues related to overseas operations.
· No Exploration Risk. Our portfolio is comprised of mature fields with proven reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on exploration drilling and the high degree of speculation in making new discoveries.
· Exploit and Develop Existing Properties. We intend to add proved reserves to, and increase production from, our existing properties through the application of advanced technologies,
The above table identifies a 16,422,506 Mcf reduction in natural gas reserves for revisions of prior estimates. Approximately 7,200,000 Mcf pertains to renegotiation of a natural gas purchase contract that was not finalized at June 30, 2006; therefore, these reserves were excluded at June 30, 2006, but may be included in future reserve calculations when the natural gas purchase contract is finalized. The remaining 9,224,523 Mcf reduction is primarily due to the reassessment of natural gas production from the planned waterflood implementation in the Panhandle Field.
Standardized Measure
The standardized measure of discounted future net cash flows (“standardized measure”) and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and natural gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate.
As of June 30, 2006 and 2005, estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired.
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.
The standardized measure of discounted estimated future net cash flows related to proved crude oil and natural gas reserves at June 30, 2006 and 2005 is as follows:
Standardized Measure of Discounted Future Cash Flows:
| 2006 |
| 2005 |
| |||
Future cash inflows |
| $ | 2,812,728,000 |
| $ | 222,665,000 |
|
Future production costs |
| (737,933,000 | ) | (121,228,000 | ) | ||
Future development costs |
| (155,865,000 | ) | (2,132,000 | ) | ||
Future income taxes |
| (694,500,000 | ) | (31,606,000 | ) | ||
Future net cash flows |
| 1,224,430,000 |
| 67,699,000 |
| ||
10% annual discount |
| (881,966,000 | ) | (37,160,000 | ) | ||
Standardized measure of discounted net cash flows |
| $ | 342,464,000 |
| $ | 30,539,000 |
|
The primary changes in the standardized measure of discounted estimated future net cash flows for the year ended June 30, 2006 and 2005 are as follows:
Changes in Standardized Measure of Discounted Future Cash Flows:
| 2006 |
| 2005 |
| |||
Balance at July 1 |
| $ | 30,539,000 |
| $ | 1,500,000 |
|
Net changes in prices and production costs |
| 32,650,000 |
| 315,000 |
| ||
Net changes in future development costs |
| (48,006,000 | ) | (1,680,000 | ) | ||
Sales of oil and gas produced, net |
| (10,247,000 | ) | (2,409,000 | ) | ||
Purchases of reserves |
| 575,835,000 |
| 43,280,000 |
| ||
Revisions of previous quantity estimates |
| (19,929,000 | ) | 2,164,000 |
| ||
Previously estimated development costs incurred |
| 7,760,000 |
| 1,985,000 |
| ||
Net change in income taxes |
| (213,131,000 | ) | (14,833,000 | ) | ||
Accretion of discount |
| 3,054,000 |
| 233,000 |
| ||
Other |
| (16,061,000 | ) | (16,000 | ) | ||
Balance at June 30 |
| $ | 342,464,000 |
| $ | 30,539,000 |
|
**************************
At July 1, 2006 and 2005, the base prices used to compute the crude oil and natural gas reserves represent the NYMEX oil and natural gas prices at June 30, 2006 and 2005, respectively. For the reserves at July 1, 2006, the crude oil and natural gas prices were $73.94 per barrel and $5.83 per MMbtu, respectively. For the reserves at July 1, 2005, the crude oil and natural gas prices were $56.54 per barrel and $6.98 per MMbtu, respectively.
The above table identifies a 16,422,506 Mcf reduction in natural gas reserves for revisions of prior estimates. Approximately 7,200,000 Mcf pertains to renegotiation of a natural gas purchase contract that was not finalized at June 30, 2006; therefore, these reserves were excluded at June 30, 2006, but may be included in future reserve calculations when the natural gas purchase contract is finalized. The remaining 9,224,523 Mcf reduction is primarily due to the reassessment of natural gas production from the planned waterflood implementation in the Panhandle Properties.
Standardized Measure
The standardized measure of discounted future net cash flows (“standardized measure”) and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and natural gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate.
As of June 30, 2006 and 2005, estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired.
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.
The standardized measure of discounted estimated future net cash flows related to proved crude oil and natural gas reserves at June 30, 2006, 2005 and 2004 is as follows:
Standardized Measure of Discounted Future Cash Flows:
|
| 2006 |
| 2005 |
| 2004 |
| |||
Future cash inflows |
| $ | 2,812,728,000 |
| $ | 222,665,000 |
| $ | 7,677,000 |
|
Future production costs |
| (737,933,000 | ) | (121,228,000 | ) | (4,819,000 | ) | |||
Future development costs |
| (155,865,000 | ) | (2,132,000 | ) | (439,000 | ) | |||
Future income taxes |
| (694,500,000 | ) | (31,606,000 | ) | — |
| |||
Future net cash flows |
| 1,224,430,000 |
| 67,699,000 |
| 2,419,000 |
| |||
10% annual discount |
| (881,966,000 | ) | (37,160,000 | ) | (919,000 | ) | |||
Standardized measure of discounted future net cash flows |
| $ | 342,464,000 |
| $ | 30,539,000 |
| $ | 1,500,000 |
|
Cano Petroleum, Inc.
801 Cherry Street, Suite 3200
Fort Worth, Texas 76102
December 15, 2006
Via EDGAR and Facsimile (202) 772-9368
Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
Re: Cano Petroleum, Inc.
Ladies and Gentlemen:
Cano Petroleum, Inc. (the “Company”) hereby acknowledges the following:
(1) The Company is responsible for the adequacy and accuracy of the disclosure in the Form S-1 (File No. 333-138003) and in the Form 10-KSB for the fiscal year ended June 30, 2006 and any amendments thereto;
(2) Comments from the Securities and Exchange Commission (the “Commission”) staff or changes to disclosure in response to Commission staff comments do not foreclose the Commission from taking any action with respect to the filings; and
(3) The Company may not assert Commission staff comments as a defense to any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Very truly yours,
Cano Petroleum, Inc. |
|
|
| |||
|
|
|
|
| ||
|
|
|
|
| ||
By: | /s/ Morris B. Smith |
|
|
| ||
| Morris B. Smith |
|
|
| ||
| Senior Vice President and |
|
|
| ||