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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x         ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: June 30, 2010

OR

o           TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-32496

Cano Petroleum, Inc.

(Exact name of registrant as specified in its charter)

(817) 698-0900

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o  No x

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of December 31, 2009, was approximately $36.3 million. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

The number of shares outstanding of the registrant’s common stock, par value $.0001 per share, as of September 22, 2010 was 45,442,082 shares.

DOCUMENTS INCORPORATED BY REFERENCE

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PART I

Items 1 and 2.  Business and Properties.

Introduction

Cano Petroleum, Inc. (together with its direct and indirect subsidiaries, “Cano,” “we,” “us,” or the “Company”) is an independent oil and natural gas company. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery at a low cost. We intend to convert our proved undeveloped and/or non-proved reserves into proved producing reserves by applying water, gas and/or chemical flooding and other EOR techniques. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma.

We were organized as a corporation under the laws of the State of Delaware in May 2003 as Huron Ventures, Inc. On May 28, 2004, we merged with Davenport Field Unit, Inc., an Oklahoma corporation, and certain other entities (the “Davenport Merger”). In connection with the Davenport Merger, we changed our name to Cano Petroleum, Inc. Prior to the Davenport Merger, we were inactive with no significant operations.

As discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity / Going Concern,” on July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009.  On, July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives.  The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.  Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise new capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.

See the “Glossary of Selected Oil and Natural Gas Terms” at the end of Items 1 and 2 for the definition of certain terms in this annual report.

Our Properties

Cato Properties.  The Cato Properties include approximately 20,600 net acres across three fields in Chavez and Roosevelt Counties, New Mexico. The prime asset is the approximately 15,000 acre Cato Field, which produces from the historically prolific San Andres formation, which has been successfully waterflooded in the Permian Basin for over 30 years. The Cato Properties did not have full-scale waterflood development prior to our acquisition. Proved reserves as of June 30, 2010 attributable to the Cato Properties were 14.8 MMBOE, of which 0.9 MMBOE were PDP, 0.7 MMBOE were PDNP and 13.2 MMBOE were PUD. Net production for the three months ended June 30, 2010 was 237 BOEPD. Our working and net revenue interests are 97% and 82%, respectively.

Panhandle Properties.  The Panhandle Properties include approximately 20,400 acres in Carson, Gray and Hutchinson Counties, Texas. The Panhandle Properties did not have full-scale waterflood development prior to our acquisition. We are progressing with the execution of our waterflood development plans at the Cockrell Ranch and Harvey Units. We have received approval of the waterflood permits at the Pond Lease and at the Olive-Cooper Lease, two of our planned mini-floods. Proved reserves as of June 30, 2010 attributable to the Panhandle Properties were 23.4 MMBOE, of which 2.4 MMBOE were PDP and 21.0 MMBOE were PUD. Net production for the three months ended June 30, 2010 was 546 BOEPD. Our working and net revenue interests are 100% and 81%, respectively.

Desdemona Properties.  The Desdemona Properties include approximately 10,700 acres in mature oil fields in central Texas. These properties were not previously waterflooded and have mineral rights to the Barnett Shale and Duke Sands formations. Proved reserves as of June 30, 2010 attributable to the Desdemona Properties were 1.2 MMBOE, of which 0.2 MMBOE were PDP and 1.0 MMBOE were PDNP. Net production for the three months ended June 30, 2010 was 69 BOEPD. Our working and net revenue interests are 100% and 83%, respectively.

Nowata Properties.  The Nowata Properties include approximately 4,600 acres and 220 wells producing from the Bartlesville Sandstone in Nowata County, Oklahoma. The Nowata Properties were previously waterflooded. Proved reserves as of June 30, 2010 attributable to the Nowata Properties were 1.9 MMBOE, of which 1.8 MMBOE were PDP and 0.1 MMBOE were PDNP. Net production for the three months ended June 30, 2010 was 219 BOEPD. Our working and net revenue interests are 100% and 85%, respectively.

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Davenport Properties.  The Davenport Properties include approximately  2,200 acres and 28 wells in Lincoln County, Oklahoma. Proved reserves as of June 30, 2010 attributable to the Davenport Properties were 1.2 MMBOE, of which 0.7 MMBOE were PDP and 0.5 MMBOE were PDNP. Net production for the three months ended June 30, 2010 was 79 BOEPD. Our working and net revenue interests are 100% and 78%, respectively.

Waterflooding and EOR techniques such as surfactant-polymer chemical injection involve significant capital investment and extended lead times of generally a year or longer from the initial phase of a program until production increases. Generally, surfactant-polymer injection is regarded as more risky as compared to waterflood operations. As our capital budget exceeds expected cash from operations, our ability to successfully convert our PUD reserves to PDP reserves will be contingent upon our ability to obtain future financing. Further, there are inherent uncertainties associated with the production of oil and natural gas as well as price volatility. See “Item 1A—Risk Factors.”

Our Strategy

·                  Exploit and Develop Existing Properties.  We believe we have an attractive portfolio of assets to implement our business plan. We intend to add proved reserves to, and increase production from, our existing properties through the application of commonly used EOR technologies, including water, gas and chemical flooding and other techniques.

·                  Drill Known Formations.  Our portfolio is composed of mature fields with proved primary and/or secondary reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on wildcat exploration drilling of new formations and the high degree of speculation associated with making new discoveries, but the application of commonly used secondary and/or tertiary recovery methods to increase production and reserves.

·                  Acquire Strategic Assets.  We seek to acquire low-cost, onshore U.S. assets with reserves suitable for EOR techniques. We will continue to target acquisitions that meet our engineering and operational standards in a financially prudent manner.  Due to our current liquidity constraints, we are not able to make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future.

Proved Reserves

The following table summarizes proved reserves as of June 30, 2010 and was prepared according to the rules and regulations of the Securities and Exchange Commission (“SEC”).

Summary of Oil and Gas Reserves as of Fiscal-Year End

Based on Average Fiscal-Year Prices

Our proved oil and natural gas reserves as of June 30, 2010 have been prepared by Haas Petroleum Engineering Services, Inc., our independent petroleum engineers. The reserve estimates as of June 30, 2010 include the effects of the

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SEC’s final rule, Modernization of Oil and Gas Reporting, issued in December 2008.  This final rule is effective for annual reports on Form 10-K for years ending on or after December 31, 2009.

As defined in the SEC rules, proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injections) are included in the “proved” classification when successful testing by a pilot project, or the operations of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling, production history and from changes in economic factors.

We have not reported our reserves to any federal authority or agency other than the SEC pursuant to our filings with the SEC.

The prices used to compute the crude oil and natural gas proved reserves represent the unweighted average first-day-of-the-month NYMEX crude oil and natural prices for the past 12 fiscal months ended June 30, 2010 pursuant to the previously discussed SEC’s final rule, which we compute to be $75.76 per barrel and $4.10 per MMBtu, respectively.

See Note 16 to our Consolidated Financial Statements regarding the internal controls we use in our reserves estimation effort and the qualifications of the technical person primarily responsible for overseeing the preparation and audit of the reserves estimates.

Proved Undeveloped Reserves

As of June 30, 2010, we had a total of 34.2 MMBOE of proved undeveloped reserves, which is a 4.8 MMBOE decrease as compared to 39.0 MBOE of proved undeveloped reserves as of June 30, 2009.

The primary reason for the 4.8 MMBOE decrease are reduced PUD reserves at the Panhandle Properties of 4.4 MMBOE.  Our independent petroleum engineers, Haas Petroleum Engineering Services, Inc. (“Haas”) utilized the East Schafer Ranch waterflood as the analogy for assessing the PUD reserves for each lease of the Panhandle Properties. The East Shafer Ranch waterflood experienced a secondary recovery of 11% of the original oil in place, or OOIP, which equated to a secondary to primary ratio of 0.35. Haas, based solely on its professional experience and engineering judgment, determined that for the purpose of reporting the Panhandle Properties’ proved reserves, they would limit each of the Panhandle Properties’ waterflood recovery factors to a 0.35 secondary to primary ratio as a maximum, and not use a percentage of OOIP to determine proved reserves. In some cases, adjustments were made since the by lease production history appeared to have allocation issues. Haas’ decision to limit proved reserve recovery based upon a 0.35 secondary to primary ratio resulted in a proved reserve decrease of 3.1 MMBOE. Further, Haas looked at the delayed responses Cano has experienced at its Cockrell Ranch unit, along with reservoir conformance and permeability trends analyzed from core data, and decided to limit proved reserves to a 0.175 secondary to primary ratio for the Cockrell Ranch and the adjacent Pond Lease, resulting in a proved reserve decrease of 1.3 MMBOE. Haas determined that the reductions to the combined company’s proved reserves would be validly reclassified as probable reserves as proved reserves indicate a 90% likelihood that production will meet or exceed the booked value while probable reserves require a 50% confidence level to be so classified.

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Production/Operating Revenues

The following table presents sales, unit prices and average unit costs for the years ended June 30, 2010, 2009, and 2008.

(1)                                 Excludes the effect of commodity price risk management activities.

Productive Wells and Acreage

The following table shows our gross and net interests in productive oil and natural gas working interest wells as of September 22, 2010. Productive wells include wells currently producing or capable of production.

(1)                                 “Gross” refers to wells in which we have a working interest.

(2)                                 “Net” refers to the aggregate of our percentage working interest in gross wells before royalties or other payout, as appropriate.

We operate all of the gross producing wells presented above. As of September 22, 2010, we had 18 wells containing multiple completions.

On September 22, 2010, we had total acreage of 59,545 gross acres and 59,085 net acres, all of which was considered developed acreage. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage under lease, permit, contract or option that is not in the spacing unit for a producing well, including leasehold interests identified for exploitation drilling.

Drilling Activity

The following table shows our drilling activities on a gross basis for the years ended June 30, 2010, 2009 and 2008. We own 100% working interests in all wells drilled.

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(1)                                 “Gross” is the number of wells in which we have a working interest.

(2)                                 “Gas” means natural gas wells that are either currently producing or are capable of production.

(3)                                 “Oil” means producing oil wells.

(4)                                 “Abandoned” means wells that were dry when drilled or were abandoned without production casing being run.

Present Activities

Our present development activities primarily involve implementing waterflood injection at the Panhandle and Cato Properties, and chemical injection at the Nowata Properties. These activities are discussed in greater detail at “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Drilling Capital Development and Operating Activities Update.”

Delivery Commitment

At June 30, 2010, we had no delivery commitments with our purchasers and currently have no delivery commitments.

Title/Mortgages

Our oil and natural gas properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions as well as mortgage liens in accordance with our credit agreements. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business. See Note 5 to our Consolidated Financial Statements regarding the mortgages that we have granted under the credit agreements on all of our oil and natural gas properties.

We believe that we have generally satisfactory title to or rights in all of our producing properties. When we make acquisitions, we make title investigations, but may not receive title opinions of local counsel until we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use of them in the operation of our business.

Acquisitions

We pursue and evaluate acquisition opportunities (including opportunities to acquire oil and natural gas properties and related assets or entities owning oil and natural gas properties or related assets, and opportunities to engage in mergers, consolidations or other business combinations with entities owning oil and natural gas properties or related assets) and at any given time may be in various stages of evaluating such opportunities. Such stages include: internal financial and oil and natural gas property analysis, preliminary due diligence, the submission of an indication of interest, preliminary negotiations and negotiation of a letter of intent or negotiation of a definitive agreement.  Due to our current liquidity constraints, it is unlikely that we will make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future.

Competition

We face competition from other oil and natural gas companies in all aspects of our business, including in the acquisition of producing properties and oil and natural gas leases, and in obtaining goods, services and labor. Many of our competitors have substantially greater financial and other resources than we do. Factors that affect our ability to acquire producing properties include available funds, available information about the property and our standards established for minimum projected return on investment.

Customers

We sell our crude oil and natural gas production to multiple independent purchasers pursuant to contracts generally terminable by either party upon thirty days’ prior written notice to the other party. During the year ended June 30, 2010, 10%

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or more of our total revenues were attributable to four customers accounting for 33% (Valero Marketing Supply Co.), 22% (Coffeyville Resources Refinery and Marketing, LLC), 18% (Plains Marketing, LP), and 10% (DCP Midstream, LP) of total operating revenue, respectively. On August 4, 2009, we entered into a new Gas Purchase Contract (the “DCP Agreement”) with DCP Midstream, L.P. (“DCP”) effective on July 1, 2009, which supersedes the previous gas purchase contract, as amended, with DCP. Previously, all of our Panhandle Properties’ leases and wells were dedicated to DCP and Eagle Rock Field Services, L.P. (“Eagle Rock”). The new DCP Agreement dedicates all of our Panhandle Properties’ leases and wells to DCP. Subject to certain conditions, the term of the DCP Agreement runs until April 30, 2016 and, unless terminated upon 60 days’ prior notice, continues thereafter on a year-to-year basis. Pursuant to the terms of the DCP Agreement, we will be paid on a sliding scale based upon the volume of NGLs and natural gas it sells per each delivery point. We will continue to sell, on a month-to-month basis, natural gas and NGLs in the Texas Panhandle to Eagle Rock until such time as any given well is added to new delivery points on the DCP pipeline. As of June 30, 2010, we had redirected approximately 80% of the natural gas production previously delivered to Eagle Rock to DCP.  Revenue enhancements under the DCP Agreement should offset the effect of volumes sold to Eagle Rock.

Title to the produced commodities transfers to the purchaser at the time the purchaser collects or receives such commodities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering systems.

In the event that one or more of these significant purchasers ceases doing business with us, we believe that there are potential alternative purchasers with whom we could establish new relationships and that those relationships would result in the replacement of one or more lost purchasers. We would not expect the loss of any single purchaser to 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 could negatively impact the prices we receive.

Governmental Regulation

Our operations are subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

The production of crude oil and natural gas is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Texas, Oklahoma and New Mexico, the states in which we own and operate properties, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Texas, Oklahoma and New Mexico also restrict production to the market demand for crude oil and natural gas. These regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sales of crude oil, natural gas and gas liquids within its jurisdiction.

Transportation and Sale of Natural Gas

Our natural gas sales were approximately 20% of our total sales during the year ended June 30, 2010. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates and various other matters, by the Federal Energy Regulatory Commission (“FERC”). Federal wellhead price controls on all domestic natural gas were terminated on January 1, 1993, and none of our natural gas sales prices are currently subject to FERC regulation. We cannot predict the impact of future government regulation on our natural gas operations.

Insurance

Our insurance policies currently provide for $1,000,000 general liability coverage for bodily injury and property damage including pollution, underground resources, blow-out and cratering. In addition, we have $1,000,000 coverage for

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our contractual obligations to our service contractors using their equipment downhole if it is damaged as a result of a blow-out. We have an “Owned- Hired and Non-Owned” commercial automobile liability limit of $1,000,000. We also have secured $50,000,000 umbrella coverage in excess of the general liability and automobile liability. Additionally, we have a $2,000,000 policy for control of well, redrill, and pollution on drilling wells and a $2,000,000 policy for control of well, redrill and pollution on producing wells.

Environmental Regulations

Our operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to human health and environmental protection. These laws and regulations may, among other things, require acquisition of a permit before drilling or development commences, restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with development and production activities, and limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our development and production activities or imposes environmental protection requirements that result in increased costs to us or the oil and natural gas industry in general.

We conduct our development and production activities to comply with all applicable environmental regulations, permits and lease conditions, and we monitor subcontractors for environmental compliance. While we believe our operations conform to those conditions, we remain at risk for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities of prior owners or operators of properties in which we own interests.

Occupational Safety Regulation

We are subject to various federal and state laws and regulations intended to promote occupational health and safety. Although all of our wells are drilled by independent subcontractors under our “footage” or “day rate” drilling contracts, we have adopted environmental and safety policies and procedures designed to protect the safety of our own supervisory staff and to monitor all subcontracted operations for compliance with applicable regulatory requirements and lease conditions, including environmental and safety compliance. This program includes regular field inspections of our drill sites and producing wells by members of our operations staff and internal assessments of our compliance procedures. We consider the cost of compliance a manageable and necessary part of our business.

Federal, State or Native American Leases

Our operations on federal, state or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies.

Employees

We and our wholly-owned subsidiaries have 44 employees as of September 22, 2010.  All of our employees are full-time employees. None of our employees are represented by a union. We have never experienced an interruption in operations from any kind of labor dispute, and we consider the working relationships among the members of our staff to be generally good.

Principal Executive Offices

Our principal executive offices are located at The Burnett Plaza, 801 Cherry Street, Suite 3200, Fort Worth, TX 76102. Our principal executive offices consist of 24,303 square feet and are subject to a lease that expires on June 2014. See Note 15 to our Consolidated Financial Statements regarding our lease payments now and in the future.

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Internet Address/Availability of Reports

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are made available free of charge on our website at http://www.canopetro.com as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC. The information presented on our website is not considered to be part of this filing or any other filing that we make with the SEC.

Glossary of Selected Oil and Natural Gas Terms

“Bbl.” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

“BOE.” Barrels of oil equivalent. BTU equivalent of six thousand cubic feet (Mcf) of natural gas which is equal to the BTU equivalent of one barrel of oil.

“BOEPD” BOE per day.

“BTU.” British Thermal Unit.

“BWIPD.” Barrels of water injected per day.

“DRY HOLE.” A development or exploratory well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“ENHANCED OIL RECOVERY” or “EOR.” The use of certain methods, such as waterflooding or gas injection, into existing wells to increase the recovery from a reservoir.

“EXPLORATORY WELL” A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir. We incur costs associated with secondary and tertiary techniques that involve drilling and equipping exploratory wells. This occurs within reservoirs for which we already have proved developed reserves recorded from existing primary or secondary development; however, there are no proved reserves for subsequent secondary or tertiary activities.

“FLUID INJECTION.” Pumping fluid into a producing formation to increase or maintain reservoir pressure and, thus, production.

“GROSS ACRES” or “GROSS WELLS.” The total number of acres or wells, as the case may be, in which a working or any type of royalty interest is owned.

“MBbl.” One thousand Bbls.

“MBOE.” One thousand BOE.

“Mcf.” One thousand cubic feet of natural gas.

“MMBOE.” One million BOE.

“MMcf.” One million cubic feet of natural gas.

“NET ACRES” or “NET WELLS.” The sum of the fractional working or any type of royalty interests owned in gross acres or wells, as the case may be.

“PRIMARY RECOVERY.” The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.

“PRODUCING WELL” or “PRODUCTIVE WELL.” A well that is capable of producing oil or natural gas in economic quantities.

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“PDP” or “PROVED DEVELOPED PRODUCING RESERVES.” The oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“PDNP” or “PROVED DEVELOPED NON-PRODUCING RESERVES.” The oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, but are not currently producing.

“PORE VOLUME INJECTION” or “PVI” means the injection of water or surfactants, polymers and other additives into the void space of a producing formation. The amount of a pore volume injection or PVI is the amount of void space of a producing formation that has been displaced with water or surfactants, polymers and other additives.

“PROVED RESERVES.” The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“PUD” or “PROVED UNDEVELOPED RESERVES.” The oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“ROYALTY INTEREST.” An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of production costs.

“SECONDARY RECOVERY.” The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

“STANDARDIZED MEASURE.” Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable changes, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess inflows over a company’s tax basis in the associated properties. Tax credits, net operating loss carryforwards and permanent differences also are considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

“SURFACTANT-POLYMER FLOODING” AND “ALKALINE-SURFACTANT-POLYMER (“ASP”) FLOODING.” Enhanced oil recovery techniques that can be employed to recover additional oil over and above primary and secondary recovery methods. Low concentrations of surfactants, polymers and other additives that are added to the waterflood operations already in place to “clean” stubborn or hard to reach oil from the reservoir.

“TERTIARY RECOVERY.” The use of improved recovery methods that not only restores formation pressure but also improves oil displacement or fluid flow in the reservoir and removes additional oil after secondary recovery.

“U.S.” The United States of America.

“WATERFLOODING.” A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and sweep oil into the producing wells.

“WORKING INTEREST.” The operating interest (not necessarily as operator) that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all exploration, development and operational costs including all risks in connection therewith.

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Item 1A.  Risk Factors.

Our business involves a high degree of risk. Investors should carefully consider the risks and uncertainties described below. Each of the following risks may materially and adversely affect our business, results of operations and financial condition. These risks may cause the market price of our common stock to decline, which may cause you to lose all or a part of the money you paid to buy our common stock.

Risks Related to Our Industry

Crude oil and natural gas prices are volatile. A substantial or sustained decline in prices could adversely affect our financial position, financial results, cash flows and access to capital.

Our revenues and operating results depend primarily upon the prices we receive for the crude oil and natural gas we produce and sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Historically, the markets for crude oil and natural gas have been volatile and they are likely to continue to be volatile. The prices we receive for our crude oil and natural gas are based upon factors that are beyond our control, including:

·                  worldwide and domestic demands and supplies of oil and natural gas;

·                  weather conditions;

·                  the price and availability of alternative fuels;

·                  the availability of pipeline capacity;

·                  the price and level of foreign imports;

·                  domestic and foreign governmental regulations and taxes;

·                  the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

·                  political instability or armed conflict in oil-producing regions; and

·                  the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future crude oil and natural gas price movements with any certainty. Declines in crude oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves.

Government regulation may adversely affect our business and results of operations.

Oil and natural gas operations are subject to various and numerous federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, spacing of wells, injection of substances, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. Certain federal, state and local laws and regulations applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations, exist for the purpose of protecting the human health and the environment. The transportation and storage of refined products include the risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies and private parties for natural resources damages, personal injury, or property damages and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined and unrefined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. As a result, we may incur substantial expenditures and/or liabilities to third parties or governmental entities which could have a material adverse effect on us.

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The oil and natural gas industry is capital intensive, and we may not be able to raise the capital needed to conduct our operations as planned or to make strategic acquisitions.

The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition of, exploration for and development of, crude oil and natural gas reserves. Due to our current liquidity constraints, it is unlikely that we will make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future.

Historically, we have financed capital expenditures with cash generated by operations, proceeds from bank borrowings and sales of equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

·                  our proved reserves;

·                  the level of oil and natural gas we are able to produce from existing wells;

·                  the prices at which oil and natural gas are sold; and

·                  our ability to acquire, locate and produce new reserves.

Any one of these variables can materially affect our ability to access the capital markets.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to fund future development projects. We may, from time to time, seek additional financing, either in the form of bank borrowings, public or private sales of debt or equity securities or other forms of financing, or consider selling non-core assets to raise additional operating capital. However, we may not be able to obtain additional financing or sell non-core assets upon terms acceptable to us.

Any prolonged, substantial reduction in the demand for oil and gas, or distribution problems in meeting this demand, could adversely affect our business.

Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. We may also have to shut-in some of our wells temporarily due to a lack of market or adverse weather conditions. If the demand for oil and gas diminishes, our financial results would be negatively impacted.

In addition, there are limitations related to the methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production, any of which could have a negative impact on its results of operation and cash flows.

Environmental liabilities could adversely affect our financial condition.

The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

· well drilling or workover, operation and abandonment;

· waste management;

· land reclamation;

· financial assurance under the Oil Pollution Act of 1990; and

· controlling air, water and waste emissions.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs of

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production, development or exploration, or decreased production, and may affect our costs of acquisitions.

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance policies currently provide for $1,000,000 general liability coverage for bodily injury and property damage including pollution, underground resources, blow-out and cratering. In addition, we have $1,000,000 coverage for our contractual obligations to our service contractors using their equipment downhole if it is damaged as a result of a blow-out. We have “an “Owned-Hired and Non-Owned” Commercial Automobile liability limit of $1,000,000. We also have secured $50,000,000 umbrella coverage in excess of the general liability and automobile liability. There is a $2,000,000 policy for control of well, redrill, and pollution on drilling wells and a $2,000,000 policy for control of well, redrill and pollution on producing wells. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future, we may not be able to obtain insurance at premium levels that justify its purchase.

We do not insure against the loss of oil or natural gas reserves as a result of operating hazards, insure against business interruption or insure our field production equipment against loss. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. Additionally, pollution and similar environmental risks generally are not fully insurable.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Budget of the U.S. Government, Fiscal Year 2011, includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. In March 2010, the EPA announced a proposed rulemaking that would expand its final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production facilities. If the proposed rule is finalized in its current form, reporting of GHG emissions from such facilities would be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Federal and state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases. The EPA has already made findings and issued proposed regulations that could lead to the imposition of restrictions on greenhouse gas emissions from motor vehicles and certain stationary sources and that could require us to establish and report an inventory of greenhouse gas emissions. In addition, the U.S. Congress has been considering various bills that would establish an economy-wide cap-and-trade program to reduce U.S. emissions of

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greenhouse gases, including carbon dioxide and methane. Such a program, if enacted, could require phased reductions in greenhouse gas emissions over several or many years as could the issuance of a declining number of tradable allowances to sources that emit greenhouse gases into the atmosphere. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which contains comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market.  The new legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation.  The financial reform legislation contains significant derivatives regulation, including provisions requiring certain transactions to be cleared on exchanges and containing a requirement to post cash collateral (commonly referred to as “margin”) for such transactions as well as certain clearing and trade-execution requirements in connection with our derivative activities. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions.  However, we do not know the definitions that the CFTC will actually promulgate nor how these definitions will apply to us.  The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer counterparties for our commodities hedging transactions.  The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  In addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability.  Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. In addition,

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in March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Thus, even if the pending bills are not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the SDWA.

Risks Related to Our Business

Our auditors have issued a “going concern” audit opinion.

Our consolidated financial statements as of June 30, 2010 have been prepared on the assumption that we will continue as a going concern.  Our independent accountants have issued a report dated September 22, 2010 stating that our significant losses from operations and net capital deficiency raise substantial doubt as to our ability to continue as a going concern.  Investors in our securities should review carefully the report of Hein & Associates LLP.  There can be no assurance that we will be able to continue as a going concern.

We have no borrowing capacity under our credit agreements, and unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.

We have sustained recurring losses and negative cash flows from operations.  Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of equity financings, borrowings under our credit agreements, the sale of assets and cash flows from operating activities.  As of June 30, 2010, we had approximately $0.3 million of cash and cash equivalents available to fund operations.  See Note 2 to our Consolidated Financial Statements.

On July 20, 2010, we terminated our announced merger with Resaca that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009.  On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives, with a goal of maximizing economic value for our shareholders.  The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.

We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived covenant compliance issues for the period ended June 30, 2010 and potential covenant compliance issues for the period ending September 30, 2010, set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete our strategic alternatives process. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.

The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business.  As a result of losses incurred and our current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded.  The ability of the Company to continue as a going concern will be dependent upon the outcome of the strategic alternatives review.  Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.  We can provide no assurance that we will be successful in our efforts to execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital.

We are subject to potential early repayments as well as restrictions pursuant to the terms of our Series D Convertible Preferred Stock which may adversely impact our operations.

Pursuant to the terms of our Series D Convertible Preferred Stock (“the Preferred Stock”), if a “triggering event” occurs, the holders of our Preferred Stock will have the right to require us to redeem their Preferred Stock at a price of at least 125% of the $1,000 per share stated value of the Preferred Stock plus accrued dividends.  “Triggering events” include the following:

·                  our common stock is suspended from trading or fails to be listed on the AMEX, the New York Stock Exchange,

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the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market;

·                  we fail to convert and do not cure this failure within 10 business days after the conversion date or give notice of our intention not to comply with a request for conversion;

·                  we fail to pay for at least 5 business days any amount when due pursuant to the terms of the Preferred Stock or any documents related to the sale and registration rights of the Preferred Stock, common stock and warrants;

·                  we take certain actions, or third parties take certain actions, with regard to bankruptcy;

·                  we default on any indebtedness which default is not waived and the applicable grace period has expired; or

·                  we breach any representation, warranty, covenant or other term or condition of any document relating to the sale and registration rights relating to the Preferred Stock, the common stock and the warrants, which, to the extent such breach is curable, such breach is not cured within 7 business days.

There is no guarantee that we would be able to repay the amounts due under our Preferred Stock upon the occurrence of a “triggering event.”

In addition, we cannot issue any preferred stock that is senior or on par with the Preferred Stock with regard to dividends or liquidation without the approval of holders of a majority of the Preferred Stock.

If we file for bankruptcy protection, holders of our common stock and preferred stock may be severely diluted or eliminated entirely in connection with a bankruptcy filing or restructuring transaction.

If we are unable to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.  As a result, we will likely file for bankruptcy or seek similar protection.  Moreover, it is possible that our creditors may seek to initiate involuntary bankruptcy proceedings against us or against one or more of our subsidiaries, which would force us to make defensive voluntary filing(s) of our own.  In addition, if we restructure our debt or file for bankruptcy protection, it is very likely that our common stock and preferred stock will be severely diluted if not eliminated entirely.

Our limited history makes an evaluation of us and our future difficult and profits are not assured.

In view of our limited history in the oil and natural gas business, you may have difficulty in evaluating us and our business and prospects. Since May 2004, we have acquired rights in oil and natural gas properties and undertaken certain exploitation activities. We are in the early stages of two waterfloods and one ASP project. You must consider our business and prospects in light of the risks, expenses and difficulties frequently encountered by companies similar to ourselves. Generally, for our business plan to succeed, we must successfully undertake the following activities:

·                  develop our oil and natural gas properties, including the successful application of EOR technologies, to the point at which oil and natural gas are being produced in commercially viable quantities;

·                  contract with third parties regarding services necessary to develop our oil and natural gas properties;

·                  contract with transporters and purchasers of our oil and natural gas production;

·                  maintain access to funds to pursue our capital-intensive business plan;

·                  comply with all applicable laws and regulations;

·                  implement and successfully execute our business strategy;

·                  find and acquire rights in strategic oil and natural gas properties;

·                  respond to competitive developments and market changes; and

·                  attract, retain and motivate qualified personnel.

There can be no assurance that we will be successful in undertaking such activities. Our failure to successfully undertake most of the activities described above could materially and adversely affect our business, prospects, financial

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condition and results of operations. There can be no assurance that sales of our oil and natural gas production will be able to sustain profitability in any future period.

We are subject to many restrictions imposed by our lenders under our credit agreements and consent and forbearance agreements which may adversely impact our future operations.

We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived potential covenant compliance issues for the periods ending June 30, 2010 and September 30, 2010, set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete its strategic alternatives process. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.

If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.

Our business strategy includes developing and acquiring interests in mature oil fields with established primary and/or secondary reserves that may possess significant remaining upside exploitation potential by implementing various secondary and/or tertiary EOR techniques. As we continue our business plan, we may require additional capital to finance acquisitions as well as to conduct our EOR operations. Due to our current liquidity constraints, it is unlikely that we will make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future. Additionally, in the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implement our business strategy, we may be required to curtail operations or develop a different strategy, which could adversely affect our financial condition and results of operations. Further, any debt financing must be repaid and redeemable preferred stock must be redeemed regardless of whether or not we generate profits or cash flows from our business activities.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

This annual report contains estimates of our proved reserves. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Approximately 80% of our total proved reserves as of June 30, 2010 consisted of undeveloped reserves, and those reserves may not ultimately be developed or produced.

Approximately 80% of our total proved reserves as of June 30, 2010 were undeveloped. While we plan to develop and produce all of our proved reserves, these reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, nor at the costs we have budgeted, or at all. As of June 30, 2010, estimated development costs for our PDNP and PUD reserves were approximately $7.0 million and $303.5 million, respectively, through 2019.

We may not achieve the production growth we anticipate from our properties or properties we acquire.

Our operational strategy is to implement waterflood and EOR techniques upon our existing properties. The performance of waterflood and EOR techniques is often difficult to predict and takes an extended period of time from first investment until actual production. Additionally, we may not achieve the anticipated production growth from properties we own or acquire in the future.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our historical growth has been due in part to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from waterflood and EOR techniques, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform reviews of acquired properties which we believe are generally consistent with industry practices. However, such reviews will not reveal all existing or potential

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problems. In addition, these reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Additionally, we do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties located in onshore United States. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions.

Exploration and development drilling and the application of waterflooding and EOR techniques may not result in commercially productive reserves.

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. 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 and permitting 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 crude oil and natural gas activities, whether developmental or exploratory, involve these risks, exploratory activities involve greater risks of failure to find and produce commercial quantities of crude oil or natural gas.

The departure of key management and personnel could adversely affect our ability to run our business.

Our future success is dependent on the personal efforts, performance and abilities of key management, including S. Jeffrey Johnson, our Chairman and Chief Executive Officer; Benjamin Daitch, Senior Vice President and Chief Financial Officer; Michael J. Ricketts, Vice President and Principal Accounting Officer; and Phillip Feiner, Vice President, Corporate Secretary and General Counsel. All of these individuals are integral parts of our daily operations. We have employment agreements with each of them. We do not maintain any key life insurance policies for any of our executive officers or other personnel. The loss of any officer could significantly impact our business until adequate replacements can be identified and put in place.

As a result of our strategic alternatives process, we are operating with a reduced work force which may affect our ability to run our business.  Additionally, we may not be able to hire qualified replacements for lost employees in the future.

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We face strong competition from larger oil and natural gas companies.

Our competitors include large integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of these competitors are well-established companies with substantially larger operating staffs and greater capital resources than we have. These larger competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in the industry.

The geographic concentration of our oil and gas reserves may have a greater effect on our ability to sell oil and gas compared to larger, more geographically diverse companies and may make us more sensitive to price volatility.

All of our oil and gas reserves are located in Texas, New Mexico and Oklahoma. Since our reserves are not as diversified geographically as many of our larger, more geographically diverse competitors, our business could be more subject to local conditions than other, more diversified companies. Any regional events, including price fluctuations, natural disasters, oil and gas processing or transportation interruptions, and restrictive regulations, that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified. For example, if a hurricane strikes certain areas of the Texas Gulf Coast, the price received for our natural gas sales may be negatively impacted due to the temporary closure of natural gas pipelines or natural gas liquids processing plants in the region impacted by the hurricane.

Our business will depend on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas that we produce.

The marketability of our crude oil and natural gas production will depend in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of crude oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations, financial condition and prospects.

Our ability to use net operating loss carryovers to offset future taxable income may be limited.

Depending on the outcome of our strategic alternatives review as discussed in Note 2 of the Consolidated Financial Statements, our federal income tax net operating loss (“NOL”) carryforwards could be subject to the ownership change limitation provisions of the Internal Revenue Code. This will result in a limitation on the use of NOL carryforwards to a specified amount per year. The Company expects to be able to fully utilize these existing NOL carryforwards in future years. However, there can be no certainty that any of our NOL carryforwards will be utilized by us in the future.

If the waterflood project at the Cockrell Ranch Unit of the Panhandle Properties is not successful, the aggregate reserves of the Panhandle Properties would be significantly reduced or eliminated.

Cano is currently undertaking a waterflood project at the Cockrell Ranch Unit on 62 injection wells and 71 producing wells on 1,023 developed acres. Production has increased from roughly 10 BOEPD to over 100 BOEPD since the initial phase of the project was started in July 2007. A number of performance issues, caused by using prior injectors that were open-hole completed, has limited the rate of project response. Cano has embarked on an active isolation program to address these issues and retained a third-party engineering firm to perform simulation modeling. The modeling results have not been completed, as it has been postponed pending the final results of our strategic alternatives review. Once completed, it is believed that waterflood production growth will more closely track the analog East Schafer Ranch response profile. Under the analogous East Schafer Ranch profile, the Cockrell Ranch Unit production would increase from the current levels of 40 BOEPD to approximately 270 BOEPD or roughly 4 BOEPD per producing well within the next 18 to 24 months after completion. The Cockrell Ranch unit contains 301 MBOE of PDP reserves based on actual performance to date and 1,782

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MBOE of remaining PUD reserves. Should the project response at the Cockrell Ranch not match the expectations for the PUD reserve profile, the reserves for this project area would be significantly reduced or eliminated. Moreover, a complete failure at the Cockrell Ranch Unit waterflood would impair the PUD reserve calculations for the properties immediately adjacent to the Cockrell Ranch, and could partially impair the remainder of the Panhandle Properties.

Derivative activities create a risk of potentially limiting the ability to realize profits when prices increase.

Pursuant to the terms of our credit agreements, we are required to maintain our existing commodity derivative contracts to mitigate the impact of a decline in crude oil and natural gas prices. These commodity derivative contracts could prevent us from realizing the full advantage of increases in crude oil or natural gas prices if the NYMEX crude oil and natural gas prices exceed the contract price ceiling. In addition, these transactions may expose us to the risk of financial loss if the counterparties to our derivative contracts fail to perform under the contracts. Also, increases in crude oil and natural gas prices negatively affect the fair value of our commodity derivatives contracts recorded on our balance sheet and, consequently, our reported net income. Changes in the recorded fair value of our derivatives contracts are marked to market through earnings and the decrease in the fair value of these contracts during any period could result in significant charges to earnings. We are currently unable to estimate the effects on earnings in future periods, but the effects could be significant.

Failure to maintain effective internal controls could have a material adverse effect on our operations.

We are subject to Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, we may be in violation of our lending covenants, investors could lose confidence in our reported financial information and the price of our stock could decrease as a result.

During our evaluation of disclosure controls and procedures for the year ended June 30, 2010, we concluded that we maintained effective internal control over financial reporting as of June 30, 2010, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

There can be no guarantee that we will not have deficiencies in our disclosure controls and internal controls in the future.

Our business involves many operating risks, which may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

·                  fires;

·                  natural disasters;

·                  explosions;

·                  pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;

·                  weather;

·                  failure of oilfield drilling and service tools;

·                  changes in underground pressure in a formation that causes the surface to collapse or crater;

·                  pipeline ruptures or cement failures;

·                  environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and

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·                  availability of needed equipment at acceptable prices, including steel tubular products.

Any of these risks can cause substantial losses resulting from:

·                  injury or loss of life;

·                  damage to and destruction of property, natural resources and equipment;

·                  pollution and other environmental damage;

·                  regulatory investigations and penalties;

·                  suspension of our operations; and

·                  repair and remediation costs.

Part of our business is seasonal in nature which may affect the price of our oil and natural gas sales and severe weather may adversely impact our ability to deliver oil and natural gas production.

Weather conditions affect the demand for and price of oil and natural gas. Demand for oil and natural gas is typically higher during winter months than summer months. However, warm winters can also lead to downward price trends. Therefore, our results of operations may be adversely affected by seasonal conditions. Severe weather can cause interruptions to our production and temporarily shut-in production from our wells.

Unfavorable results of litigation could have a material adverse impact on our financial statements.

We are subject to a variety of claims and lawsuits that arise from time to time in the ordinary course of our business.  Management currently believes that resolving any of such matters, individually or in the aggregate, will not have a material adverse impact on our financial position or results of operations.  The litigation and claims are subject to inherent uncertainties and management’s view of these matters may change in the future.  There exists the possibility of a material adverse impact on our financial position and the results of operations for the period in which the effect of an unfavorable final outcome becomes probable and reasonably estimable.  Please see “Legal Proceedings” for a discussion of our material pending legal proceedings.

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 significant production growth from our waterfloods, our lease operating expense per BOE should remain higher than companies drilling for primary production. These higher operating costs could have an adverse effect on our results of operations.

Risks Related to Our Common Stock

Failure to obtain a satisfactory result from our strategic alternatives process could adversely affect our common stock price, and our future business and financial results.

On July 20, 2010, following our termination of the Agreement and Plan of Merger with Resaca we announced the initiation of a strategic alternatives process designed to achieve the best available economic value for our shareholders.  The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, or potential business combinations.  We currently have a severe shortage of working capital and funds to pay our liabilities, and we currently have no available borrowing capacity under our senior or subordinated credit agreements.  We were not in compliance with the interest coverage ratio and leverage ratio at June 30, 2010.  On August 6, 2010, we finalized Forbearance Agreements with our lenders that set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for $0.8 million. The cash proceeds from the sale of the derivative contracts is expected to provide us sufficient liquidity to complete our strategic alternatives process. Our Consolidated Financial Statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the losses incurred and current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. The ability of Cano to continue as a

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going concern is dependent upon the strategic alternatives process, as previously discussed. There can be no assurance that our strategic alternatives process will adequately resolve issues regarding our liquidity or going concern status.

Our historic stock price has been volatile and the future market price for our common stock may continue to be volatile. This may make it difficult for you to sell our common stock for a positive return on your investment.

The public market for our common stock has historically been very volatile. On September 16, 2010, our closing price on the NYSE Amex was $0.75. Any future market price for our shares may continue to be very volatile. The stock market in general has experienced extreme price and volume fluctuations that often are unrelated or disproportionate to the operating performance of companies. Broad market factors and the investing public’s negative perception of our business may reduce our stock price, regardless of our operating performance. Market fluctuations and volatility, as well as general economic, market and political conditions, could reduce our stock price. As a result, this may make it difficult or impossible for you to sell our common stock for a positive return on your investment.

If we fail to meet continued listing standards of NYSE Amex, our common stock may be delisted which would have a material adverse effect on the price of our common stock.

In order for our securities to be eligible for continued listing on NYSE Amex, we must remain in compliance with certain listing standards. Among other things, these standards require that we remain current in our filings with the SEC and comply with certain provisions of the Sarbanes-Oxley Act of 2002. If we were to become noncompliant with NYSE Amex’s continued listing requirements, our common stock may be delisted which would have a material adverse affect on the price of our common stock. This is also a “triggering event” under our Preferred Stock which could cause the holders of our Preferred Stock to have the right to require us to redeem their Preferred Stock at a price of at least 125% of the $1,000 per share stated value of the Preferred Stock plus accrued dividends.

If we are delisted from NYSE Amex, our common stock may become subject to the “penny stock” rules of the SEC, which would make transactions in our common stock cumbersome and may reduce the value of an investment in our stock.

The SEC has adopted Rule 3a51-1 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that is not listed on a national securities exchange or registered national securities association’s automated quotation system and has a market price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, Rule 15g-9 requires:

·                  that a broker or dealer approve a person’s account for transactions in penny stocks; and

·                  the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

·                  obtain financial information and other information regarding the investment experience and objectives of the person; and

·                  make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

·                  sets forth the basis on which the broker or dealer made the suitability determination; and

·                  confirms the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

If securities analysts downgrade our stock or cease coverage of us, the price of our stock could decline.

The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control the reports these analysts publish about us. Furthermore, there are many large, well-established, publicly-traded companies active in our industry and market, which may make it less likely that we

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will receive widespread analyst coverage. If one or more of the analysts who do cover us downgraded our stock, our stock price would likely decline rapidly. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.

We do not pay dividends on our common stock.

We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business, including capital expenditures, and to retire debt. Any decisions to pay dividends on the common stock in the future will depend upon our profitability at the time, available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our credit agreements and our Preferred Stock.

Provisions in our corporate governance and loan documents, the terms of our Preferred Stock and Delaware law may delay or prevent an acquisition of Cano, which could decrease the value of our common stock.

Our certificate of incorporation, our Preferred Stock, our bylaws, our credit agreements and the Delaware General Corporation Law contain provisions that may discourage other persons from initiating a tender offer or takeover attempt that a stockholder might consider to be in the best interest of all stockholders, including takeover attempts that might result in a premium to be paid over the market price of our stock.

The terms of our Preferred Stock give its holders the right to have their Preferred Stock redeemed upon a “change of control.” In addition, the terms of our Preferred Stock do not permit us to enter into certain transactions that would constitute a “change of control” unless the successor entity assumes all of our obligations relating to the Preferred Stock and the holders of a majority of our Preferred Stock approve such assumption and the successor entity is publicly-traded on the NYSE Amex, the New York Stock Exchange, the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market.

In addition, subject to the terms of the Preferred Stock, we are authorized to issue additional shares of preferred stock. Subject to the terms of the Preferred Stock and our certificate of incorporation, our board of directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the board of directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:

·                  restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;

·                  dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;

·                  dilution of the equity interest of common stock and other series of preferred stock; and

·                  limitation on the right of holders of common stock and other series of preferred stock to share in Cano’s assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.

The terms of our Preferred Stock and the provisions in our corporate governance documents regarding the granting of additional preferred stock may deter or render more difficult proposals to acquire control of our company, including proposals a stockholder might consider to be in his or her best interest, impede or lengthen a change in membership of our Board of Directors and make removal of our management more difficult. Furthermore, Delaware law imposes some restrictions on mergers and other business combinations between our company and owners of 15% or more of our common stock. These provisions apply even if an acquisition proposal is considered beneficial by some stockholders and therefore could depress the value of our common stock.

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The conversion price of our Preferred Stock may be lowered if we issue shares of our common stock at a price less than the existing conversion price which could cause further dilution to our common stockholders.

Subject to certain exclusions, if we issue common stock at a price less than the existing conversion price for our Preferred Stock, the conversion price shall be adjusted downward which would further dilute our common stock holders upon conversion.

Our Preferred Stock has voting rights both together with and separate from our common stock which could adversely affect our common stockholders.

The holders of our Preferred Stock vote together with the holders of our common stock on an as-converted basis, subject to a limitation on how many votes the Series D Convertible Preferred Stock holders may cast if the conversion price falls below $4.79. In addition, approval of holders of a majority of the Series D Convertible Preferred Stock is required for us to take the following actions:

·                  to modify the certificate of incorporation or bylaws in a manner adverse to the Preferred Stock;

·                  increase or decrease the number of authorized shares of Preferred Stock;

·                  create any class of preferred stock that has a preference over or is in parity with the Preferred Stock with respect to dividends or liquidation;

·                  purchase, repurchase or redeem any share of common stock;

·                  pay dividends or make any other distribution on the common stock; or

·                  circumvent a right of the Preferred Stock.

These voting rights may have an adverse impact on the common stock and the voting power of our common stockholders.

Since we are a United States real property holding corporation, non-U.S. investors may be subject to U.S. federal income tax (including withholding tax) on gains realized on disposition of our shares, and U.S. investors selling our shares may be required to certify as to their status in order to avoid withholding.

Since we are a United States real property holding corporation, a non-U.S. holder of our common stock will generally be subject to U.S. federal income tax on gains realized on a sale or other disposition of our common stock. Certain non-U.S. holders of our common stock may be eligible for an exception to the foregoing general rule if our common stock is regularly traded on an established securities market during the calendar year in which the sale or disposition occurs. However, we cannot offer any assurance that our common stock will be so traded in the future.

If our common stock is not considered to be regularly traded on an established securities market during the calendar year in which a sale or disposition occurs, the buyer or other transferee of our common stock will generally be required to withhold tax at the rate of 10% of the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable Treasury regulations.

Item 1B.  Unresolved Staff Comments.

None.

Item 2.  Properties.

See “Items 1 and 2. Business and Properties.”

Item 3.  Legal Proceedings.

Burnett Case

On March 23, 2006, the following lawsuit was filed in the 100th Judicial District Court in Carson County, Texas: Cause No. 9840, The Tom L. and Anne Burnett Trust, by Anne Burnett Windfohr, Windi Phillips, Ben Fortson, Jr., George Beggs, III and Ed Hudson, Jr. as Co-Trustees; Anne Burnett Windfohr; and Burnett Ranches, Ltd. v. Cano Petroleum, Inc.,

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W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and natural gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas.

The plaintiffs (i) allege negligence and gross negligence and (ii) seek damages, including, but not limited to, damages for damage to their land and livestock, certain expenses related to fighting the fire and certain remedial expenses totaling approximately $1.7 million to $1.8 million. In addition, the plaintiffs seek (i) termination of certain oil and natural gas leases, (ii) reimbursement for their attorney’s fees (in the amount of at least $549,000) and (iii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The owner of the remainder of the mineral estate, Texas Christian University, intervened in the suit on August 18, 2006, joining Plaintiffs’ request to terminate certain oil and gas leases. On June 21, 2007, the judge of the 100th Judicial District Court issued a Final Judgment (a) granting motions for summary judgment in favor of Cano and certain of its subsidiaries on plaintiffs’ claims for (i) breach of contract/termination of an oil and gas lease; and (ii) negligence; and (b) granting the plaintiffs’ no-evidence motion for summary judgment on contributory negligence, assumption of risk, repudiation and estoppel affirmative defenses asserted by Cano and certain of its subsidiaries.

The Final Judgment was appealed and a decision was reached on March 11, 2009, as the Court of Appeals for the Tenth District of Texas in Amarillo affirmed in part and reversed in part the ruling of the 100th Judicial District Court. The Court of Appeals (a) affirmed the trial court’s granting of summary judgment in Cano’s favor for breach of contract/termination of an oil and gas lease and (b) reversed the trial court’s granting of summary judgment in Cano’s favor on plaintiffs’ claims of Cano’s negligence. The Court of Appeals ordered the case remanded to the 100th Judicial District Court. On March 30, 2009, the plaintiffs filed a motion for rehearing with the Court of Appeals and requested a rehearing on the affirmance of the trial court’s holding on the plaintiffs’ breach of contract/termination of an oil and gas lease claim. On June 30, 2009, the Court of Appeals ruled to deny the plaintiff’s motion for rehearing. On August 17, 2009 we filed an appeal with the Texas Supreme Court to request the reversal of the Court of Appeals ruling regarding our potential negligence. On December 11, 2009, the Texas Supreme Court declined to hear Cano’s appeal. Therefore, this case has been remanded to the district court for trial on the negligence claims and the trial date has been set for November 2, 2010.

Due to the inherent risk of litigation, the ultimate outcome of this case is uncertain and unpredictable. At this time, Cano management continues to believe that this lawsuit is without merit and will continue to vigorously defend itself and its subsidiaries, while seeking cost-effective solutions to resolve this lawsuit. Based on our knowledge and judgment of the facts as of September 22, 2010, we believe our financial statements present fairly the effect of the actual and the anticipated future costs to resolve this matter as of June 30, 2010.

There is no remaining insurance coverage for any claims associated with this fire litigation.

Securities Litigation against Outside Directors

On October 2, 2008, a lawsuit (08 CV 8462) was filed in the United States District Court for the Southern District of New York, against David W. Wehlmann; Gerald W. Haddock; Randall Boyd; Donald W. Niemiec; Robert L. Gaudin; William O. Powell, III and the underwriters of the June 26, 2008 public offering of Cano common stock (“Secondary Offering”) alleging violations of the federal securities laws. Messrs. Wehlmann, Haddock, Boyd, Niemiec, Gaudin and Powell were Cano outside directors on June 26, 2008. At the defendants’ request, the case was transferred to the United States District Court for the Northern District of Texas.

On July 2, 2009, the plaintiffs filed an amended complaint that added as defendants Cano, Cano’s Chief Executive Officer and Chairman of the Board, Jeff Johnson, Cano’s former Senior Vice President and Chief Financial Officer, Morris B. “Sam” Smith, Cano’s current Senior Vice President and Chief Financial Officer, Ben Daitch, Cano’s Vice President and Principal Accounting Officer, Michael Ricketts and Cano’s former Senior Vice President of Engineering and Operations, Patrick McKinney, and dismissed Gerald W. Haddock, a former director of Cano, as a defendant. The amended complaint alleges that the prospectus for the Secondary Offering contained statements regarding Cano’s proved reserve amounts and standards that were materially false and overstated Cano’s proved reserves. The plaintiff is seeking to certify the lawsuit as a class action lawsuit and is seeking an unspecified amount of damages. On July 27, 2009, the defendants moved to dismiss the lawsuit. On December 3, 2009, the U.S. District Court for the Northern District of Texas granted motions to dismiss all claims brought by the plaintiffs. On December 18, 2009, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On April 5, 2010, Cano filed its appellate brief to support its position.  On April 19, 2010, the plaintiffs filed their response brief. On August 4, 2010, the U.S. Court of Appeals for the Fifth Circuit affirmed the dismissal by the U.S. District Court for the Northern District of Texas of all claims by the plaintiffs.  By affirming the decision of the lower court, the U.S. Court of Appeals for the Fifth Circuit agreed that the plaintiff’s complaint failed to state a claim upon which

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relief could be granted, and thus found merit in dismissing the lawsuit.  Due to the inherent risk of litigation, the outcome of this lawsuit is uncertain and unpredictable; however, Cano, its officers and its outside directors intend to continue to vigorously defend the lawsuit.

Cano is cooperating with its directors and officers liability insurance carrier regarding the defense of the lawsuit. We believe that the potential amount of losses resulting from this lawsuit in the future, if any, will not exceed the policy limits of Cano’s directors’ and officers’ liability insurance.

Other

Occasionally, we are involved in other various claims and lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management does not believe that the ultimate resolution of any current matters that are not set forth above will have a material effect on our financial position or results of operations. Management’s position is supported, in part, by the existence of insurance coverage, indemnification and escrow accounts. None of our directors, officers or affiliates, owners of record or beneficial owners of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.

Section 7.6 of the Merger Agreement with Resaca provided for the Company and Resaca to share transaction expenses related to the printing, filing and mailing of the registration statement, the proxy/prospectus, and the solicitation of stockholder approvals.  On September 2, 2010, we filed an action against Resaca in the Tarrant County District Court seeking a declaratory judgment to clarify the scope and determine the amount of any expenses that are reimbursable under Section 7.6 of the Merger Agreement.

Environmental

To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Item 4.  (Removed and Reserved).

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our shares of common stock are listed on the NYSE Amex under the trading symbol “CFW.” For the years ended June 30, 2009 and 2010, the following table sets forth the high and low sales prices per share of common stock for each quarterly period. On September 16, 2010, the closing sale price of our common stock on the NYSE Amex was $0.75.

Holders

As of September 16, 2010, our shares of common stock were held by approximately 106 stockholders of record. In many instances, a record stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares. We estimate that, as of September 16, 2010, there were approximately 7,300 beneficial holders who own shares of our common stock in street name.

Dividends

We have not declared any dividends to date on our common stock. We have no present intention of paying any cash dividends on our common stock in the foreseeable future, as we intend to reinvest earnings, if any, into our operations. Our

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credit agreements do not permit us to pay dividends on our common stock. In addition, the terms of our Preferred Stock do not permit us to pay dividends on our common stock without the approval of the holders of a majority of the Preferred Stock.

For the year ended June 30, 2010, the Preferred Stock dividend was $1.8 million, of which $1.1 million were paid-in-kind dividends. On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.

During the year ended June 30, 2010, there were no equity securities issued pursuant to transactions exempt from registration requirements under the Securities Act of 1933, as amended, that were not disclosed previously in Current Reports on Form 8-K or Quarterly Reports on Form 10-Q.

ISSUER PURCHASES OF EQUITY SECURITIES

(1)                                 Shares of our common stock were delivered to us during the fourth quarter of 2010 to satisfy tax withholding obligations by S. Jeffrey Johnson, Benjamin Daitch, Patrick McKinney, Michael J. Ricketts and Phillip Feiner pursuant to the terms of the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan to satisfy tax withholding obligations related to the vesting of their respective restricted stock awards.  In addition, Mr. McKinney forfeited 78,334 restricted common shares of Cano stock upon his resignation on May 31, 2010.

Item 6.  Selected Financial Data.

Not applicable.

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain of the matters discussed under the captions “Business and Properties,” “Legal Proceedings,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this annual report may constitute “forward-looking” statements for purposes of the Securities Act of 1933, and the Securities Exchange Act of 1934 and, as such, may involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. When used in this report, the words “anticipates,” “estimates,” “plans,” “believes,” “continues,” “expects,” “projections,” “forecasts,” “intends,” “may,” “might,” “could,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. Various factors could cause the actual results, performance or achievements to differ materially from our expectations. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements disclosed in this annual report (“Cautionary Statements”), including, without limitation, those statements made in conjunction with the forward-looking statements included under the captions identified above and otherwise herein. All written and oral forward-looking statements attributable to us are qualified in their entirety by the Cautionary Statements. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law and you are cautioned not to place undue reliance on any forward-looking statement.

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Overview

Introduction

We are an independent oil and natural gas company. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery at a low cost. We intend to convert our proved undeveloped and/or unproved reserves into proved producing reserves by applying water, gas and/or chemical flooding and other EOR techniques. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma.

During our first three years of operations, our primary objective was to achieve growth through acquiring existing, mature crude oil and natural gas fields. Since then, we have focused on waterflood operations in our two largest properties, Panhandle and Cato. These development activities are more clearly described below under “—Drilling Capital Development and Operating Activities Update.”

As discussed under “—Liquidity / Going Concern,” on July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009.  On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives.  The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.

Proved Reserves

On September 14, 2010, we announced the results of our year-year reserves review as of June 30, 2010 as prepared by Haas, our independent petroleum engineer. The following table compares our proved reserves by property as of June 30, 2010 to June 30, 2009. The amounts are presented in thousands of barrels oil equivalent (“MBOE”).

(in MBOE)

As of June 30, 2010, our proved reserves total 42.5 MMBOE, or 6.6 MMBOE lower than our proved reserves of 49.1 MMBOE at June 30, 2009.  The primary contributors to the 6.6 MMBOE decrease are reduced PUD reserves at the Panhandle Properties of 4.4 MMBOE, reduced PDP reserves at the Cato Properties of 0.9 MMBOE, the sale of certain wells in the Panhandle Properties of 0.5 MMBOE (as discussed in Note 7 to our Consolidated Financial Statements) and production for the twelve-month period ended June 30, 2010 of 0.4 MMBOE.

Haas utilized the East Schafer Ranch waterflood as the analogy for assessing the PUD reserves for each lease of the Panhandle Properties. The East Shafer Ranch waterflood experienced a secondary recovery of 11% of the original oil in place, or OOIP, which equated to a secondary to primary ratio of 0.35. Haas, based solely on its professional experience and engineering judgment, determined that for the purpose of reporting the Panhandle Properties’ proved reserves, they would limit each of the Panhandle Properties’ waterflood recovery factors to a 0.35 secondary to primary ratio as a maximum, and not use a percentage of OOIP to determine proved reserves. In some cases, adjustments were made since the by lease production history appeared to have allocation issues. Haas’ decision to limit proved reserve recovery based upon a 0.35 secondary to primary ratio resulted in a proved reserve decrease of 3.1 MMBOE. Further, Haas looked at the delayed responses Cano has experienced at its Cockrell Ranch unit, along with reservoir conformance and permeability trends analyzed from core data, and decided to limit proved reserves to a 0.175 secondary to primary ratio for the Cockrell Ranch and the adjacent Pond Lease, resulting in a proved reserve decrease of 1.3 MMBOE. Haas determined that the reductions to the combined company’s proved reserves would be validly reclassified as probable reserves as proved reserves indicate a 90% likelihood that production will meet or exceed the booked value while probable reserves require a 50% confidence level to be so classified.

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The reduction of PDP reserves at Cato Properties is a result of lower field production rates associated with lower water injection rates at the waterflood.

The reserve estimates as of June 30, 2010 include the effects of the SEC’s final rule, Modernization of Oil and Gas Reporting, issued in December 2008.  This final rule is effective for annual reports on Form 10-K for years ending on or after December 31, 2009.

The prices used to compute the crude oil and natural gas proved reserves represent the unweighted average first-day-of-the-month NYMEX crude oil and natural prices for the past 12 fiscal months ended June 30, 2010, pursuant to the previously discussed SEC’s final rule, which we compute to be $75.76 per barrel and $4.10 per MMBtu, respectively, as compared to $68.89 per barrel and $3.71 per MMBtu on June 30, 2009.  Crude oil reserves accounted for 78% of our total proved reserves at June 30, 2010.

The table below summarizes the changes in our proved reserves from June 30, 2009 to June 30, 2010.

Extensions and Discoveries totaling 279 MBOE include newly identified behind-pipe opportunities at our Cato and Panhandle Properties.  Additionally, approximately 60 MBOE of previously categorized PDNP reserves at the Desdemona Properties were reclassified to PDP reserves as we are in the midst of a development project to return to production previously shut-in gas wells from the Duke Sand formation.  Our development activities are more fully described below under “—Development Capital Expenditures and Operating Activities Update.”

Drilling Capital Development and Operating Activities Update

For the quarter ending June 30, 2010 (“current quarter”) our production averaged 1,149 net barrels of oil equivalent per day (BOEPD), which was 52 BOEPD (4.3%) lower as compared to production of 1,201 BOEPD for the quarter ended June 30, 2009 (“prior year quarter”). Production for the year ended June 30, 2010 (“2010 Fiscal Year”) of 1,102 net BOEPD was 42 BOEPD (3.7%) lower as compared to the year ended June 30, 2009 (“2009 Fiscal Year”) of 1,144 net BOEPD.  These reported production amounts exclude the sale of Certain Panhandle Properties, as discussed in Note 7 to the Consolidated Financial Statements, which averaged 98 BOEPD during the 2010 Fiscal Year.  For both the current quarter and 2010 Fiscal Year, the production decreases were primarily attributed to mandatory lower waterflood injection volumes at our Cato Properties, as discussed below. At our other properties, normal field declines of production were offset by workover activities and return-to-production (“RTP”) program at the Desdemona Field.

For the 2010 Fiscal Year, we incurred development capital expenditures of $12.2 million (excludes capitalized general and administrative and interest expenses). Our development capital budget was designed to maintain our current level of production and to minimize drawing on the ARCA while we pursued the completion of the planned merger with Resaca. The development capital expenditures were incurred as follows:

·                  $4.5 million at the Cato Properties,

·                  $6.9 million at the Panhandle Properties, and

·                  $0.8 million at the Desdemona Properties.

The following is a discussion of our field level activity during the 2010 Fiscal Year.

Cato Properties.

Our 2010 Fiscal Year development capital plan included expanding the waterflood footprint from 640 acres to approximately 1,000 acres by adding three new injection wells, which were put into service during the quarter ended December 31, 2009. We have identified a new source of water in a non-productive formation within our acreage, and have

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confirmed that the water well is capable of producing 2,500 to 3,000 barrels of water per day. This new water source formation has been penetrated in a number of existing wellbores in the Cato Properties and confirms the reservoir continuity necessary to validate it as a reliable water source for future expansion of the Cato waterflood.  As we develop this new water source, we will be able to increase the waterflood footprint without decreasing the injection rate at our existing injectors, which should enable us to maintain production from existing producing wells at current levels. We averaged 14,000 barrels of water injection per day (“BWIPD”) during the quarter ended September 30, 2009.  We experienced a decrease to 12,000 BWIPD through March 31, 2010, as we measured increasing injection pressures in the northern part of the flood area and we were required, under our existing waterflood permit, to reduce the injection rate in these wells. On May 6, 2010, we received administrative approval from the New Mexico Oil and Gas Conservation Division (“NMOGCD”) to increase injection pressures at the 14 active wells to our current physical plant capabilities of approximately 21,000 BWIPD.  As of August 31, 2010, we have maintained an injection rate of 12,000 BWIPD, which is less than the approved rate from the NMOGCD as we have reduced capital spending pending the outcome of our strategic alternatives review.  We have seen increased fluid production rates and corresponding increasing crude oil rates from this waterflood.  We have submitted an application to the NMOGCD to expand the waterflood operations and expect their approval by December 2010.

The Cato Properties will be developed through the purchase of additional equipment to increase water injection and to increase fluid production and crude oil rates from this waterflood. Additional development plans for the Cato Properties include behind-pipe recompletions, restoration of production from the Tom-Tom and Tomahawk fields, and the drilling of a Morrow formation test well.   Net production at the Cato Properties for the quarter ended June 30, 2010 was 237 BOEPD, which was 96 BOEPD lower than the prior year quarter of 333 BOEPD. Net production at the Cato Properties for the 2010 Fiscal Year was 257 BOEPD, which was 39 BOEPD lower than 2009 Fiscal Year of 296 BOEPD.  The decreases for the current quarter and 2010 Fiscal Year resulted from the reduction in injected water and redistribution of water injection at the waterflood.

Please see “Business Properties — Our Properties — Cato Properties” for a description of the Cato Properties.

Panhandle Properties.

In the quarter ended September 30, 2009, we established a controlled water injection pattern at the Cockrell Ranch unit to gauge the effects of optimizing water injection into the highest remaining crude oil saturation intervals of the Brown Dolomite formation.  We essentially performed a “Mini-Flood” in the key target interval at the Cockrell Ranch unit. The result of this field observation helped us determine an optimal pattern for waterflooding the balance of the Cockrell Ranch unit with an increasingly predicable production profile. Moreover, the field observation should improve the planning of future development programs for the remaining leases located within our Panhandle Properties. To isolate the observed wells, we had temporarily shut-in production during most of the quarter ended September 30, 2009, which reduced Panhandle production by 25 net BOEPD.  All production that was shut-in for the controlled injection project was restored on September 28, 2009. We have experienced positive results from the controlled injection project.  Oil production from wells in the affected area has increased to at or above target levels of 8-12 BOEPD on a per well basis.

Net production at the Panhandle Properties, as adjusted for the sale of Certain Panhandle Properties as discussed in Note 7 to the Consolidated Financial Statements, for the quarters ended June 30, 2010 and 2009 were 546 BOEPD and 517 BOEPD, respectively.   Net production for the Panhandle Properties for the 2010 and 2009 Fiscal Years was 494 BOEPD and 495 BOEPD, respectively. During the 2010 Fiscal Year, we constructed gathering lines to redirect natural gas production from Eagle Rock Field Services L.P. (“Eagle Rock”) to DCP Midstream, LP (“DCP”).  As of June 30, 2010, we had redirected approximately 80% of the natural gas production previously delivered to Eagle Rock to DCP.

Please see “Business Properties — Our Properties — Panhandle Properties” for a description of the Panhandle Properties.

Desdemona Properties.

During the 2010 Fiscal Year, we implemented a project to return to production previously shut-in gas wells from the Duke Sand formation.  We converted approximately 311 MBOE of previously PDNP reserves to PDP reserves for 12 RTP’d gas wells in December 2009. Production increased from 46 BOEPD for the quarter ended December 31, 2009 to 69 BOEPD for the quarter ended March 31, 2010 without the benefit of selling any natural gas liquids (“NGLs”). We RTP’d an additional 13 wells during the quarter ended June 30, 2010. Production from all of the RTP’d natural gas wells, including associated NGL recovery from our gas plant, is expected to be approximately 10-20 Mcfe per day for each gas well returned to production. We have re-equipped our gas plant to handle the increased natural gas production and the gas plant became functional during August 2010.  Daily production from the Desdemona Properties is projected to be 100 — 110 BOEPD.

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During the quarter ended March 31, 2010, we drilled one new well to a total depth of 3,650 feet to test the Marble Falls, Atoka and Strawn Sand formations.  We have completed the new well in the Strawn Sand formation at a depth of 1,750 feet.  As of August 31, 2010, the well produced 5 BOEPD.  We are currently evaluating this well to optimize production.

Net production at the Desdemona Properties for the quarters ended June 30, 2010 and June 30, 2009 was 69 BOEPD and 59 BOEPD, respectively.  Net production at the Desdemona Properties for the 2010 and 2009 Fiscal Years was 55 BOEPD and 61 BOEPD, respectively. During July 2009, we shut-in our Barnett Shale natural gas wells based upon the then current and the outlook for natural gas prices from the Barnett Shale wells.

Please see “Business Properties — Our Properties — Desdemona Properties” for a description of the Desdemona Properties.

Nowata Properties.  Proved reserves as of June 30, 2010 attributable to the Nowata Properties were 1.9 MMBOE, of which 1.8 MMBOE were PDP and 0.1 MMBOE were PDNP. Net production for the quarters ended June 30, 2010 and June 30, 2009 was 219 BOEPD and 218 BOEPD, respectively. Net production for the 2010 and 2009 Fiscal Years was 219 BOEPD and 221 BOEPD, respectively.  We are currently assessing our operations at the Nowata Properties to increase production, including constructing an additional gas gathering system and optimizing current infrastructure. Please see “Business Properties — Our Properties — Nowata Properties” for a description of the Nowata Properties.

Davenport Properties.  Proved reserves as of June 30, 2010 attributable to the Davenport Properties were 1.2 MMBOE, of which 0.7 MMBOE were PDP and 0.5 MMBOE were PDNP. Net production for the quarters ended June 30, 2010 and June 30, 2009 was 79 BOEPD and 74 BOEPD, respectively. Net production for the 2010 and 2009 Fiscal Years was 76 BOEPD and 71 BOEPD, respectively. Please see “Business Properties — Our Properties — Davenport Properties” for a description of the Davenport Properties.

Industry Conditions

We operate in a competitive environment for (i) acquiring properties, (ii) marketing oil and natural gas and (iii) attracting trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. Some of our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and obtain capital for investment in the oil and natural gas industry.

EOR techniques involve significant capital investment and an extended period of time, generally a year or longer, until production increases. Generally, surfactant-polymer injection is regarded as more risky as compared to waterflood operations. Our ability to successfully convert PUD reserves to PDP reserves will be contingent upon our ability to obtain future financing and/or raise additional capital. Further, there are inherent uncertainties associated with the production of crude oil and natural gas, as well as price volatility. See “Item 1A.Risk Factors.”

Liquidity and Capital Resources

Liquidity / Going Concern

At June 30, 2010, we had cash and cash equivalents of $0.3 million. We had negative working capital of $66.9 million, which includes $66.5 million of long-term debt that was shown as a current liability. For the year ended June 30, 2010, we had cash flow used in operations of $0.2 million, which included $1.9 million of merger-related cash expenses.

On July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009.  On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives, with a goal of maximizing economic value for our shareholders.  The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.

We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived potential covenant compliance issues for the periods ending June 30, 2010 and September 30, 2010, set certain deadlines for the execution of our strategic alternatives review and allowed us

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to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete its strategic alternatives review. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.

The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred and our current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. The ability of the Company to continue as a going concern will be dependent upon the outcome of the strategic alternatives review. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.

On December 28, 2007, our universal shelf registration statement was declared effective by the SEC for the issuance of common stock, preferred stock, warrants, senior debt and subordinated debt up to an aggregate amount of $150.0 million. After the issuance of common stock on July 1, 2008, we have $96.0 million of availability under this registration; however, the amount of securities which we may offer pursuant to this shelf registration statement during any twelve-month period shall be limited to one-third of the aggregate market value of the common equity of the Company held by our non-affiliates since our public float is not in excess of $75.0 million. We may periodically offer one or more of these securities in amounts, prices and on terms to be announced when and if the securities are offered. At the time any of the securities covered by the registration statement are offered for sale, a prospectus supplement will be prepared and filed with the SEC containing specific information about the terms of any such offering. The universal shelf registration statement expires on December 31, 2010.

Credit Agreements

At June 30, 2010 and 2009, the outstanding amount due under our credit agreements was $66.5 million and $55.7 million, respectively. The $66.5 million at June 30, 2010, consisted of outstanding borrowings under the amended and restated credit agreement (the “ARCA”) and subordinated credit agreement (the “SCA”) of $51.5 million and $15.0 million, respectively. At June 30, 2010, the average interest rates under the ARCA and SCA were 2.85% and 6.54%, respectively.

Forbearance Agreements

On August 5, 2010, we executed a Consent and Forbearance Agreement (the “Senior Forbearance Agreement”) with Natixis and Union Bank, N.A. (“UBNA”), relating to existing and potential defaults under the ARCA dated December 17, 2008 among Cano, Natixis and UBNA and a Consent and Forbearance Agreement (together with the Senior Forbearance Agreement, the “Forbearance Agreements”) with UnionBanCal Equities, Inc. (“UBE”), relating to existing defaults under the SCA dated December 17, 2008 between Cano and UBE (as amended, the SCA and together with the ARCA, the “Credit Agreements”).  Pursuant to the Forbearance Agreements, Natixis, UBNA and UBE agreed to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of the following defaults (the “Designated Defaults”):

·                  Cano’s failure to pay the amendment fees required by Amendment No. 2 to each of the Credit Agreements;

·                  Cano’s failure to provide an Internal Engineering Report and accompanying officer’s certificate on or before March 30, 2010, as required by the Credit Agreements;

·                  Cano’s potentially prohibited cash payments with respect to its shares of Preferred Stock on June 29, 2010 and June 30, 2010; and

·                  Cano’s failure to comply with certain financial covenants contained in the Credit Agreements for the quarter ended June 30, 2010 and potential failure to comply with such covenants for the quarter ended September 30, 2010.

The Forbearance Agreements also contain the following material terms:

·                  Natixis, UBNA and UBE consent to Cano’s termination of certain natural gas hedge contracts.

·                  Cano may not make any indirect or direct cash payment, cash dividend or cash distribution in respect of its shares of Preferred Stock.

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·                  Natixis, UBNA and UBE agree to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of Cano’s potential failure to pay interest upon receipt of a default notice on the unpaid principal amount of each advance under the SCA on September 30, 2010.

·                  Cano must establish, on or before August 10, 2010, an electronic data room with information available to persons that may be interested in consummating an asset purchase, merger, combination, refinancing, recapitalization or other similar transaction with Cano (each, a “Prospective Transaction”).

·                  Cano must execute, on or before September 15, 2010, a letter of intent evidencing the parties’ intent to consummate a Prospective Transaction that will close on or before October 29, 2010 (the “Definitive Transaction”).

·                  Cano must execute definitive documentation providing for a Definitive Transaction on or before September 30, 2010.

·                  Cano must close a Definitive Transaction on or before October 29, 2010.

·                  Cano must deliver to UBNA and UBE a weekly written report of the parties visiting the electronic data room and a summary of progress and correspondence with respect to any Prospective Transaction.

·                  Cano must pay a forbearance fee in an amount equal to 1% of the aggregate principal amount of the advances outstanding under the Credit Agreements as of August 5, 2010 and the amendment fees required by Amendment No. 2 to each of the Credit Agreements upon receipt of proceeds from a Definitive Transaction.

·                  The aggregate commitments of Natixis and UBNA to lend to Cano pursuant to the ARCA are permanently reduced to $51.5 million, the current amount outstanding.

·                  UBNA and UBE shall not redetermine Cano’s borrowing bases under the Credit Agreements at any time prior to the termination of the Forbearance Agreements.

The Forbearance Agreements will terminate on the earlier of October 29, 2010, the date of Cano’s failure to comply with any of the terms described above and the date of the occurrence or existence of any default under either Credit Agreement, other than the Designated Defaults.

Regarding our compliance with the material items of the Forbearance Agreements:

·                  Prior to August 10, 2010, we did establish an electronic data room with information available to persons interested in consummating a Proposed Transaction.

·                  On August 10, 2010, we sold certain natural gas commodity derivative contracts to our counterparty, UBNA, for $0.8 million.

·                  At September 15, 2010, we were in discussions with parties regarding potential transaction structures and did not deliver a letter of intent pursuant to the Forbearance Agreements as discussed above. We continue to work with potential parties and our lenders on transaction structures.

The ARCA and SCA are discussed in greater detail below.

ARCA

On December 17, 2008, we finalized a new $120.0 million Amended and Restated Credit Agreement (the “ARCA”) with UBNA and Natixis. UBNA is the Administrative Agent and Issuing Lender of the ARCA. The current amount outstanding under the ARCA is equal to the commitment of $51.5 million. Per the terms of the Forbearance Agreement, the ARCA’s borrowing base shall not be redetermined.

Based upon the terms of the Forbearance Agreement, our interest rate is the sum of the one, two or three month LIBOR rate and 2.75%. As of the Forbearance Agreement, there will not be a commitment fee and we are deemed fully borrowed.

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Unless specific events of default occur, the maturity date of the ARCA is December 17, 2012. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. The ARCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBNA, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBNA, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.

SCA

On December 17, 2008, we finalized a $25.0 million SCA among Cano and UBE, as the Administrative Agent. On March 17, 2009, we borrowed the maximum available amount of $15.0 million under this agreement.

The interest rate is the sum of (a) the one, two or three month LIBOR rate (at our option) and (b) 6.0%. Through March 17, 2009, we owed a commitment fee of 1.0% on the unborrowed portion of the available borrowing amount. We no longer have a commitment fee since we borrowed the full $15.0 million available amount.

Unless specific events of default occur, the maturity date is June 17, 2013. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change as defined in the SCA. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. The SCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests of Cano; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBE, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBE, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.

Credit Agreement Covenant Compliance

Both the ARCA and the SCA have a current ratio covenant that requires us to maintain a ratio of not less than 1.00 to 1.00 for each fiscal quarter. The current ratio is calculated by dividing current assets (as defined in both credit agreements) by current liabilities (as defined in both credit agreements). Current assets include unused borrowing base under the ARCA and the aggregate availability under the SCA. Current liabilities exclude all current portions of long-term debt other than any current debt relating to the Preferred Stock and liabilities for asset retirement obligations. Current assets and current liabilities exclude derivative assets and liabilities. At June 30, 2010, our ratio of current assets to current liabilities was 1.89 to 1.00. The calculation and reconciliation of current assets and current liabilities, as defined by GAAP, to current assets and current liabilities, as defined in the credit agreements is as follows (in thousands):

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(1)                                       Represents the $60.0 million borrowing base under the ARCA at June 30, 2010, less $51.5 million of debt outstanding under the ARCA at June 30, 2010.

We were not in compliance with the covenants relating to our leverage ratio and interest coverage ratio for the quarters ended December 31, 2009, March 31, 2010 and June 30, 2010. The leverage ratio is the ratio of consolidated Debt (as defined in both credit agreements) to consolidated EBITDA (as defined in both credit agreements) for the cumulative four fiscal quarter periods.  Under the ARCA and SCA, the leverage ratio cannot be greater than 4.00 to 1.00 and 4.50 to 1.00, respectively.  The interest coverage ratio is the ratio of consolidated EBITDA (as defined in both credit agreements) to consolidated Interest Expense (as defined in both agreements) for the cumulative four fiscal quarter periods.  Under the ARCA and SCA, the interest coverage ratio cannot be less than 3.00 to 1.00 and 2.50 to 1.00, respectively.  The Forbearance Agreements address our non-compliance with the leverage ratio and interest coverage ratio, as previously discussed.

The SCA has a minimum asset coverage ratio covenant that requires us to maintain a ratio of not less than 1.50 to 1.00. The minimum asset coverage ratio is calculated by dividing (i) Total Present Value as of the applicable determination date, which is defined as the sum of 100% of the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to (A) PDP reserves, (B) PDNP reserves and (C) PUD reserves, with the total present value of PDP reserves being at least 60% of the aggregate total present value, by (ii) consolidated Debt (as defined in the Subordinated Credit Agreement) as of the applicable determination date. At June 30, 2010, our minimum asset coverage ratio was 2.03 to 1.00, calculated as follows (in thousands):

Results of Operations—Years Ended June 30, 2010, 2009 and 2008

Overall

For the 2010 Fiscal Year, we had a loss applicable to common stock of $13.4 million, which was a $21.3 million decrease as compared to income applicable to common stock of $7.9 million for the 2009 Fiscal Year. Items contributing to the $21.3 million decrease were reduced gain on derivatives of $45.7 million, decreased income from preferred stock repurchased for less than the carrying amount of $10.9 million and lower income from discontinued operations of $10.3 million. Partially offsetting the earnings decrease were lower operating expenses of $43.9 million, which is primarily attributable to a $26.7 million charge for impairment of long-lived assets during the 2009 Fiscal Year.  Other items that decreased operating expenses were reductions to general and administrative expenses of $7.3 million, decreased exploration expense of $6.4 million and lower lease operating expenses of $2.8 million.

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For the 2009 Fiscal Year, we had income applicable to common stock of $7.9 million, which was a $29.5 million improvement as compared to the $21.6 million loss applicable to common stock for the 2008 Fiscal Year. Items that led to the improvement were increased gain on derivatives of $75.7 million, preferred stock repurchased for less than the carrying amount of $10.9 million, higher income from discontinued operations of $7.1 million and lower preferred stock dividend of $1.4 million. These positive factors were partially offset by higher operating expenses of $49.7 million, lower operating revenues of $7.9 million, lower deferred income tax benefit of $7.5 million and goodwill impairment of $0.7 million.

Operating Revenues

The table below summarizes our operating revenues:

2010 Fiscal Year v. 2009 Fiscal Year

The 2010 Fiscal Year operating revenues of $22.8 million were $0.6 million lower as compared to the 2009 Fiscal Year operating revenues of $23.4 million. The $0.6 million reduction is primarily attributable to decreased crude oil and natural gas sales volumes, which lowered revenues by $1.6 million and $0.9 million, respectively, and lower other revenues of $0.3 million.  These decreases were partially offset by increased prices received for crude oil and natural gas sales volumes of $2.1 million and $0.2 million, respectively.

Crude Oil Sales.  Our 2010 Fiscal Year crude oil sales were 23 MBbls lower as compared to the 2009 Fiscal Year due to lower sales from our Cato Properties and Panhandle Properties of 12 MBbls and 8 MBbls, respectively. The sales decrease at our Cato Properties resulted from the redistribution of water injection at the waterflood which resulted in lower production, as discussed under “Overview-Drilling Capital Development and Operating Activities Update.”

The sales decrease at the Panhandle Properties is due to the controlled injection project at the Cockrell Ranch waterflood and severe weather during January and February 2010 which temporarily curtailed production.  All Cockrell Ranch production that had been temporarily shut-in for the controlled injection project was restored on September 28, 2009.

Natural Gas Sales.  Our 2010 Fiscal Year natural gas sales were 119 MMcf lower as compared to the 2009 Fiscal Year primarily due to lower sales at the Panhandle Properties of 44 MMcf, Desdemona Properties of 36 MMcf and Cato Properties of 36 MMcf.  Lower natural gas sales at the Panhandle Properties resulted from severe weather and from the controlled production project at Cockrell Ranch waterflood, as previously discussed, and one of our gas purchasers experiencing unplanned plant outages during August 2009, September 2009, May 2010 and June 2010, which resulted in reduced natural gas and NGL sales. Lower natural gas sales at the Desdemona Properties resulted from the shut-in natural gas production from our Barnett Shale wells during July 2009, based upon the then current and near-term outlook of natural gas prices, and the temporary shut-in of our gas plant to equip the plant to handle increased natural gas production from the return to production of 25 shut-in Duke Sand gas wells as previously discussed under the “Overview—Drilling Capital Development and Operating Activities Update.”  Lower natural gas sales at the Cato Properties resulted from the purchaser temporarily declining to take natural gas production from January through March 2010.

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2009 Fiscal Year v. 2008 Fiscal Year

The 2009 Fiscal Year operating revenues of $23.4 million were $7.9 million lower as compared to the 2008 Fiscal Year operating revenues of $31.3 million. The $7.9 million reduction is primarily attributable to lower prices received for crude oil and natural gas sales, which lowered revenues by $7.9 million and $3.0 million, respectively, and by lower natural gas sales volumes, which lowered revenues by $0.7 million. These decreases were partially offset by increased crude oil sales volumes, which increased revenues by $3.7 million.

Crude Oil Sales.  For the 2009 Fiscal Year, approximately 82% of the increased crude oil sales of 60 MBbls were attributed to the waterflood development activity at the Cato Properties. Also, we had increased crude oil sales from the Panhandle Properties due to the waterflood development.

Natural Gas Sales.  For the 2009 Fiscal Year, the overall decrease in natural gas sales of 96 MMcf pertains primarily to reductions with respect to our Barnett Shale project at our Desdemona Properties. During the first half of calendar year 2008, various workovers and re-fracture stimulations were attempted to increase production. Through December 2008, these efforts were met with marginal success. In January 2009, we halted our workover program in the Desdemona Properties—Barnett Shale. Once the Barnett Shale workover activity ceased, we experienced Barnett Shale production declines of approximately 65 - 90%.

Also, higher gas production from the Cato Properties due to the aforementioned development activity was offset by lower gas production from our Panhandle Properties due to normal field decline of approximately 10% annually and temporary pipeline curtailments of gas deliveries to our gas purchasers.

Crude Oil and Natural Gas Prices

The average price we receive for crude oil sales is generally at market prices received at the wellhead, except for the Cato Properties, for which we receive below market prices due to the level of impurities in the oil. Differentials increased briefly as commodity prices rapidly declined between July 2008 and December 2008; however, the differentials have since recovered. The average price we receive for natural gas sales is approximately the market price received at the wellhead, adjusted for the value of natural gas liquids, less transportation and marketing expenses.

The average prices we received for our crude oil and natural gas sales were supplemented or reduced by commodity derivative settlements received or paid for the 2010, 2009 and 2008 Fiscal Years.  As discussed in Note 6 to our Consolidated Financial Statements, if crude oil and natural gas NYMEX prices are lower than the “floor prices,” we will be reimbursed by our counterparty for the difference between the NYMEX price and “floor price” (i.e. realized gain).  Conversely, if crude oil and natural gas NYMEX prices are higher than the derivative “ceiling prices,” we will pay our counterparty for the difference between the NYMEX price and “ceiling price” (i.e. realized loss).

Operating Expenses

2010 Fiscal Year v. 2009 Fiscal Year

For the 2010 Fiscal Year, our total operating expenses were $40.0 million, or $43.9 million lower than the 2009 Fiscal Year of $83.8 million. The 2009 Fiscal Year included an impairment of long-lived assets of $26.7 million, which is the primary reason for the overall decrease. In addition, we had reduced general and administrative of $7.3 million, reduced exploration expense of $6.4 million, lower lease operating expenses of $2.8 million and lower depletion and depreciation expense of $0.8 million.

2009 Fiscal Year v. 2008 Fiscal Year

For the 2009 Fiscal Year, our total operating expenses were $83.8 million, or $49.7 million higher than the 2008 Fiscal Year of $34.1 million. The primary contributors to the increase were an impairment of long-lived assets of $26.7 million and exploration expense of $11.4 million associated with the Desdemona Properties—Duke Sands waterflood project. In addition, we experienced increased lease operating expenses of $5.5 million, general and administrative of $4.3 million and higher depletion and depreciation of $1.8 million.

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Lease Operating Expenses

Our lease operating expenses (“LOE”) consist of the costs of producing crude oil and natural gas such as labor, supplies, repairs, maintenance, workovers and utilities.

For the 2010 Fiscal Year, our LOE was $15.7 million, which is $2.8 million lower than 2009 Fiscal Year of $18.5 million. The $2.8 million decrease resulted primarily from reduced service rates negotiated with vendors of $2.5 million, the shut-in of our Barnett Shale natural gas wells which reduced LOE by $0.6 million and lower electricity expense of $0.3 million. Partially offsetting these LOE cost reductions were increased LOE at the Cato Properties of $0.6 million to support increased focus on production activities.

For the 2010 Fiscal Year, our LOE per BOE, based on production, was reduced by $5.55 per BOE to $38.90 as compared to $44.45 for the 2009 Fiscal Year for the reasons previously discussed. For the quarter ended June 30, 2010, the LOE per BOE was $36.35.  In general, secondary and tertiary LOE is higher than the LOE for companies developing primary production because our fields are more mature and typically produce less oil and more water. However, we expect our LOE per BOE to decrease during the 2011 Fiscal Year as we realize the benefit of a full year of lower service rates with vendors. Further, we expect LOE per BOE to decrease as production increases from the waterflood and EOR development activities we have implemented and are implementing as discussed under the “Drilling Capital Development and Operating Activities Update.”

For the 2009 Fiscal Year, our LOE was $18.5 million, which is $5.5 million higher than 2008 Fiscal Year of $13.0 million. The $5.5 million increase resulted primarily from increased workover activities and general repairs at the Panhandle Properties of $4.2 million and higher operating expenses incurred at the Cato Properties of $2.1 million to support increased crude oil and natural gas sales, as discussed under “Operating Revenues,” partially offset by lower operating expenses of $1.1 million due to lower natural gas sales at the Desdemona Properties, as discussed under “Operating Revenues.” We also had higher LOE at the Davenport and Nowata Properties of $0.3 million due to increased electricity expenses, general repairs and workover expenses. The workover activities at the Panhandle Properties pertained to returning wells to production and have increased production, as discussed under “Operating Revenues.” For the 2009 Fiscal Year, our LOE per BOE was $44.45, which is an $8.38 per BOE increase as compared to $36.07 for Fiscal Year 2008.  The $8.38 per BOE increase is due to the reasons previously discussed.

Production and Ad Valorem Taxes

For the 2010 Fiscal Year, our production and ad valorem taxes were $1.9 million, which is $0.2 million lower than the 2009 Fiscal Year of $2.1 million. Our production taxes were lower by $0.1 million due to lower operating revenues and ad valorem taxes were lower by $0.1 million due to reductions in tax property valuations by taxing authorities. Our production taxes as a percent of operating revenues for the 2010 Fiscal Year of 6.3% was comparable to the 2009 Fiscal Year of 6.5%. We anticipate the 2011 Fiscal Year to be subject to similar production tax rates.

For the 2009 Fiscal Year, our production and ad valorem taxes were $2.1 million, which is comparable to 2008 Fiscal Year. Our production taxes were lower by $0.5 million due to lower operating revenues, which was offset by increased ad valorem taxes of $0.5 million. The increased ad valorem taxes were due to notification of revisions in tax property valuations by taxing authorities for the 2008 calendar year. Therefore, the 2009 Fiscal Year includes higher tax rates for the twelve months plus a charge for applying the rates to the first six months of the 2008 calendar year. Our production taxes as a percent of operating revenues for the 2009 Fiscal Year of 6.5% was comparable to the 2008 Fiscal Year of 6.6%.

General and Administrative Expenses

Our general and administrative (“G&A”) expenses consist of support services for our operating activities, legal matters and investor relations costs.

2010 Fiscal Year v. 2009 Fiscal Year

For the 2010 Fiscal Year, our G&A expenses totaled $11.8 million, which is $7.3 million lower than Fiscal Year 2009 of $19.2 million. The $7.3 million expense reduction resulted primarily from reduced litigation costs of $6.0 million, reduced share-based compensation costs of $2.1 million, and lower payroll and benefits costs of $0.9 million.  Partially offsetting these expense reductions were increased costs related to the terminated merger of $2.1 million. The reduced payroll and benefits costs resulted from workforce reductions we implemented during the quarter ended March 31, 2009, which eliminated 25% of our home office staff. The lower share-based compensation costs are directly related to reduced issuances

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of stock options and restricted stock. The litigation cost reduction occurred as we settled all but one of our fire litigation claims during the fiscal year ended June 30, 2009.

2009 Fiscal Year v. 2008 Fiscal Year

For the 2009 Fiscal Year, our G&A expenses totaled $19.2 million, which is $4.3 million higher than Fiscal Year 2008 of $14.9 million. The primary contributors to the $4.3 million increase were higher litigation costs of $4.4 million pertaining to the settlement costs and legal fees pertaining to the fire litigation and increased stock compensation expense of $0.2 million, partially offset by reduced payroll expense of $0.3 million. During the quarter ended March 31, 2009, we took steps to reduce our payroll, eliminating 25% of our home office staff. The quarter ended June 30, 2009 was the first time we realized these savings.

Exploration Expense

During the 2010 Fiscal Year, we recorded exploration expense of $5.0 million pertaining to the Nowata ASP Project. During December 2009, we finalized our performance analysis, which indicated the Nowata ASP Project did not result in significantly increased oil production quantities and is therefore considered not economically viable. Accordingly, at December 31, 2009, we recorded a $5.0 million pre-tax exploration expense.

During the 2009 Fiscal Year, we recorded exploration expense of $11.4 million pertaining to the Duke Sand waterflood project. The primary source of water for this waterflood project had been derived from our Barnett Shale wells. As we shut-in our Barnett Shale natural gas production due to uneconomic natural gas commodity prices, we no longer had an economic source of water to continue flooding the Duke Sand. Therefore, our rate of water injection had been reduced to a point where we could not consider the waterflood active. We continue to believe that this reservoir is an excellent secondary and tertiary recovery candidate; however, we do not have plans to recommence injection for the foreseeable future.

Impairment of Long-Lived Assets

During the 2010 Fiscal Year, we wrote down $0.3 million of costs associated with the ASP facility used for the Nowata ASP Project. The facility’s water filtering process did not work properly with the oil-water fluid production at our Nowata Properties. The ASP facility is portable and may be used in future pilot tertiary projects at our Cato and Panhandle Properties.

During the 2009 Fiscal Year, we recorded a $26.7 million impairment on our Barnett Shale Properties as the decline in commodity prices created an uncertainty about the likelihood of developing our reserves associated with our Barnett Shale natural gas properties within the next five years. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline and we shut-in our Barnett Shale natural gas wells. The fair value was determined using estimates of future production volumes, prices and operating expenses, discounted to a present value.

Depletion and Depreciation

For the 2010 Fiscal Year, our depletion and depreciation expense was $5.0 million, a decrease of $0.7 million as compared to the 2009 Fiscal Year depletion and depreciation expense. This includes depletion expense pertaining to our oil and natural gas properties, and depreciation expense pertaining to our field operations vehicles and equipment, natural gas plant, office furniture and computers. The decrease is due to decreased crude oil and natural gas sales volumes (net) as previously discussed under “Operating Revenues.”  For the 2010 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $13.99 per BOE, as compared to the 2009 Fiscal Year rate of $14.20 per BOE. The decreased depletion rates resulted primarily from our reserve redetermination at December 31, 2009 and periodic assessments of depletion rates during the 2010 Fiscal Year, and impairments of our Barnett Shale Properties, as previously discussed.

For the 2009 Fiscal Year, our depletion and depreciation expense was $5.7 million, an increase of $1.8 million as compared to the 2008 Fiscal Year depletion and depreciation expense. The increase is due to increased crude oil and natural gas sales volumes (net) as previously discussed under “Operating Revenues” and higher per BOE depletion rates. For the 2009 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $14.20 per BOE, as compared to the 2008 Fiscal Year rate of $10.88 per BOE. The increased depletion rates resulted from higher depletion rates for our Cato and Panhandle Properties based on our reserve estimates at June 30, 2009 and periodic assessments of depletion rates during the 2009 Fiscal Year.

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Interest Expense and Other

For the 2010, 2009 and 2008 Fiscal Years, we recorded interest expense of $1.0 million, $0.5 million and $0.7 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 5 to our Consolidated Financial Statements. The interest expense for the 2010, 2009 and 2008 Fiscal Years was reduced by $2.0 million, $1.4 million and $2.5 million, respectively, for interest cost that was capitalized to the waterflood and ASP projects discussed under the “Drilling Capital Development and Operating Activities Update.” We incurred higher interest costs during both the 2010 and 2008 Fiscal Years due to higher outstanding debt balances and higher interest rates.

Gain (Loss) on Commodity Derivatives

As discussed in Note 6 to our Consolidated Financial Statements, we have entered into financial contracts for our commodity derivatives and our interest rate swap. For the 2010 Fiscal Year, the loss on commodity derivatives of $1.9 million consisted of an unrealized loss of $6.6 million and a realized gain of $4.7 million.  For the 2009 Fiscal Year, the gain on commodity derivatives of $43.8 million consisted of an unrealized gain of $36.9 million and a realized gain on settlements of commodity derivative contracts of $6.9 million. For the 2008 Fiscal Year, the loss on commodity derivatives of $32.0 million consisted of unrealized and realized losses of $29.4 million and $2.6 million, respectively.

For the realization of settlements, if crude oil and natural gas NYMEX prices are lower than the floor prices, we will be reimbursed by our counterparty for the difference between the NYMEX price and floor price (i.e. realized gain). Conversely, if crude oil and natural gas NYMEX prices are higher than the ceiling prices, we will pay our counterparty for the difference between the NYMEX price and ceiling price (i.e. realized loss).

The unrealized gain for the 2010 Fiscal Year reflects the change in fair value of the commodity derivatives during the 2010 Fiscal Year. By their nature, these commodity derivatives can have a highly volatile impact on our earnings. A ten percent change in the NYMEX prices for crude oil and natural gas that impact our commodity derivative instruments could affect our pre-tax earnings by approximately $5.0 million.

Income Tax Benefit (Expense)

For the 2010 Fiscal Year, we had an income tax benefit of $5.3 million. For the 2009 Fiscal Year, we had income tax expense of $1.7 million.  For the 2008 Fiscal Year, we had an income tax benefit of $9.8 million. These tax amounts included taxes related to discontinued operations as shown in Note 7 to our Consolidated Financial Statements. The higher amount of income taxes for the 2009 Fiscal Year, as compared to the 2010 and 2008 Fiscal Years, is due to higher taxable income and an increase in other permanent items, as presented in Note 14 to our Consolidated Financial Statements, resulting in an aggregate rate of 107.4%. The income tax rates for the 2010 and 2008 Fiscal Years was 31.3% and 35.8%, respectively.

Income from Discontinued Operations

For the 2010, 2009 and 2008 Fiscal Years, we had income from discontinued operations of $2.1 million, $12.3 million and $5.2 million, respectively, due to our divestitures of the Pantwist, LLC; Corsicana Properties and Certain Panhandle Properties, as discussed in Note 7 to our Consolidated Financial Statements.

Preferred Stock Dividend

The preferred stock dividend for the 2010 Fiscal Year of $1.8 million was a decrease of $0.9 million from the 2009 Fiscal Year. This resulted from the November and December 2008 repurchases of preferred stock as discussed in Note 4 to our Consolidated Financial Statements. Due to the repurchases, our quarterly preferred stock dividends will be approximately $0.5 million per quarter of which 59% will be paid-in-kind, with the balance paid in cash.

The preferred stock dividend for the 2009 Fiscal Year of $2.7 million was a decrease of $1.4 million from the 2008 Fiscal Year. This resulted from the November and December 2008 repurchases of preferred stock, as previously discussed.  Also, the 2008 Fiscal Year amount includes $0.5 million of federal tax we were required to withhold in accordance with Internal Revenue Service regulations from September 2006 through June 2008. These amounts did not have a material effect to our prior period financial statements. Due to the previously discussed repurchases, we no longer have any Preferred Stock that require withholding taxes.

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On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at June 30, 2010 for the periods shown:

Off Balance Sheet Arrangements

Our off balance sheet arrangements are limited to operating leases that have not and are not reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Selected Quarterly Financial Data (Unaudited)

We derived the selected historical financial data in the table below from our unaudited interim consolidated financial statements. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The historical data presented here are only a summary and should be read in conjunction with the consolidated financial statements, related notes and other financial information included elsewhere in this annual report.

(a)                      For the quarter ended December 31, 2009, our results of operations were unfavorably impacted by unrealized loss on commodity derivatives of $5.8 million.

(b)                 For the quarter ended September 30, 2008, our results of operations were favorably impacted by $24.2 million unrealized gain on commodity derivatives resulting from a significant price decrease for both crude oil and natural gas.

(c)                      For the quarter ended December 31, 2008, our results of operations were unfavorably impacted by impairment of long-lived assets of $22.4 million, partially offset by unrealized gain on commodity derivatives.

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(d)                     For the quarter ended June 30, 2009, our results of operations were unfavorably impacted by exploration expense of $11.4 million and impairment of long-lived assets of $4.3 million.

Critical Accounting Policies

We have identified the critical accounting policies used in the preparation of our financial statements. These are the accounting policies that we have determined involve the most complex or subjective decisions or assessments.

Consolidation and Use of Estimates

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Cano and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved crude oil and natural gas reserves, which may affect the amount at which crude oil and natural gas properties are recorded. The computation of share-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. Our liabilities and assets associated with commodity derivatives involve significant assumptions related to volatility and future prices for crude oil and natural gas. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Cano’s Proved Reserves

The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices based on an unweighted 12-month average and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases. A decline in estimates of proved reserves may result from lower prices, new information obtained from development drilling and production history; mechanical problems on our wells; and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.

Our proved reserves estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserves estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.

Oil and Gas Properties and Equipment

We follow the successful efforts method of accounting. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense. The costs of drilling and equipping exploratory wells are deferred until the Company has determined whether proved reserves have been found. If proved reserves are found, the deferred costs are capitalized as part of the wells and related equipment and facilities. If no proved reserves are found, the deferred costs are charged to expense. All development activity costs are capitalized. We are primarily engaged in the development and acquisition of crude oil and natural gas properties. Our activities are considered development where existing proved reserves are identified prior to commencement of the project and are considered exploration if there are no proved reserves at the beginning of such project. 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 $1.1 million for the years ended June 30, 2010 and 2009, respectively. We recorded capitalized interest costs of $2.0 million and $1.4 million for the years ended June 30, 2010 and 2009, respectively.

Costs for repairs and maintenance to sustain or increase production from existing producing reservoirs are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

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Depreciation and depletion of producing properties are computed on the unit-of-production method based on estimated proved oil and natural gas reserves. 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, 2010 and 2009, capitalized costs related to waterflood and alkaline-surfactant-polymer (“ASP”) projects that were in process and not subject to depletion amounted to $51.6 million and $49.4 million, respectively, of which $0.0 million and $4.8 million, respectively, were deferred costs related to drilling and equipping exploratory wells associated with our ASP project, as discussed in Note 8 to our Consolidated Financial Statements.

If conditions indicate that long-term assets may be impaired, the carrying value of our properties is compared to management’s future estimated undiscounted net cash flow from the properties. If undiscounted cash flows are less than the carrying value, then the asset value is written down to fair value. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis. The impairment assessment is affected by factors such as the results of exploration and development activities, commodity price projections, remaining lease terms, and potential shifts in our business strategy.

Asset Retirement Obligation

Our financial statements reflect the fair value of our asset retirement obligation (“ARO”), which consists of future plugging and abandonment expenditures related to our oil and gas properties, that can be reasonably estimated, and discounted at our credit-adjusted risk-free rate. The asset retirement obligation is recorded as a liability at its estimated fair value at the asset’s inception, with an offsetting increase to producing properties on the consolidated balance sheets, which is depreciated such that the cost of the ARO is recognized over the useful life of the asset. Periodic accretion of the discount of the estimated liability to its expected settlement value is recorded as an expense in the consolidated statements of operations.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

Revenue Recognition

Our revenue recognition is based on the sales method. We do not have imbalances for natural gas sales since we are primarily the 100% working interest owner in our properties. We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on publicly available information. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from the purchasers are collectible. The point of sale for our crude oil and natural gas production is at our applicable field tank batteries and gathering systems; therefore, we do not incur transportation costs related to our sales of crude oil and natural gas production.

As previously discussed, for the years ended June 30, 2010, 2009 and 2008, we sold our crude oil and natural gas production to several independent purchasers. The following table shows purchasers that accounted for 10% or more of our total operating revenues: