UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: March 31, 2011

OR

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

For the transition period from                  to                

Commission File Number: 001-32496

Cano Petroleum, Inc.

(Exact name of registrant as specified in its charter)

(214) 687-0030

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

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 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 Exchange Act).  Yes o No x

The number of shares outstanding of the registrant’s common stock, par value $.0001 per share, as of May 13, 2011 was 45,354,915 shares.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

CANO PETROLEUM, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

See accompanying notes to these unaudited financial statements

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CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to these unaudited financial statements

2

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHODLERS’ EQUITY

JULY 1, 2010 THROUGH MARCH 31, 2011

(Unaudited)

See accompanying notes to these unaudited financial statements

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CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to these unaudited financial statements

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CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND USE OF ESTIMATES

Consolidation, Basis of Presentation and Use of Estimates

These interim consolidated financial statements are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Certain prior-period balances in the consolidated financial statements have been reclassified to correspond with current year classifications.  Results for interim periods are not necessarily indicative of results to be expected for a full year due in part, but not limited to, the volatility in prices for crude oil and natural gas, future prices for commodity derivatives, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of events, product demand, market competition, interruption in production, our ability to obtain additional capital, and the success of waterflooding and enhanced oil recovery techniques. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended June 30, 2010.

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 Petroleum, Inc. and its wholly-owned subsidiaries (collectively, “Cano”). 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. The computation of stock-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. The computation of mark-to-market valuations of our commodity derivatives include the observability of quoted market prices and an assessment of potential non-performance of counterparties. It is possible these estimates could be revised in the near term, and these revisions could be material.

Significant assumptions are required in the valuation of proved crude oil and natural gas reserves, which affect the amounts at which crude oil and natural gas properties are recorded. 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 estimated proved reserves could result from lower prices, adverse operating results, mechanical problems at our wells, and/or catastrophic events such as fires, hurricanes and floods. Lower prices can make it uneconomical to drill new wells or produce from existing wells with high operating costs. In addition, a decline in proved reserves will impact our assessment of our oil and natural gas properties for impairment. Our proved reserves estimates are based upon many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.  Based on our June 30, 2010 reserve report, seventy-nine percent of our proved reserves are classified as proved undeveloped reserves. Capital expenditures amounting to $310.5 million are forecasted in our reserve report. Proved undeveloped reserves may be reclassified from proved reserves to probable reserves, or permanently reduced, due to an inability to access the capital markets. To develop these reserves we will require access to the capital markets and/or consider divestitures of oil and gas properties in each of the next five years, as our projected capital expenditures are greater than projected cash flow from operations through December 2015.

New Accounting Pronouncements

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our Form 10-K for the year ended June 30, 2010.

2. LIQUIDITY / GOING CONCERN / STRATEGIC ALTERNATIVES

At March 31, 2011, we had cash and cash equivalents of $1.1 million. We had negative working capital of $103.0 million, which includes current liabilities of $66.5 million of long-term debt and $28.2 million of Series D convertible preferred stock. For the nine-month period ended March 31, 2011, we had cash flow provided by operations of $2.1 million.

We are reviewing strategic alternatives,which include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, potential business combinations, debt restructuring, including possible bankruptcy and/or recapitalizing the Company. We continue to focus on cost reduction efforts to improve both our profitability and cash flow from operations.

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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. The Consent and Forbearance Agreements were terminated as our lenders delivered Reservation of Rights Letters dated September 24, 2010 and January 5, 2011, as discussed in Note 3.  We continue to work with our lenders and advisors as we consider strategic alternatives.  As of May 13, 2011, our lenders have taken no definitive actions associated with the termination of the Consent and Forbearance Agreements.  We currently have no available borrowing capacity under our senior and subordinated credit agreements, and have very limited access to additional capital.

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. There is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded, or that the Company can continue to prepare future financial statements on a going concern basis. The ability of the Company to continue as a going concern will be dependent upon the outcome of our strategic alternatives review, crude oil and natural gas prices, sufficient liquidity to fund operations, actions by our lenders, mechanical problems at our wells and/or catastrophic events such as fires, hurricanes and floods.

3. DEBT

At March 31, 2011 and June 30, 2010, the outstanding amount due under our credit agreements was $66.5 million. The $66.5 million consisted of outstanding borrowings under the amended and restated credit agreement (the “ARCA”) and the subordinated credit agreement (the “SCA”) of $51.5 million and $15.0 million, respectively. At March 31, 2011, the average interest rates charged by the lenders under the ARCA and SCA were 3.01% and 6.31%, respectively.

On August 5, 2010, we executed a Consent and Forbearance Agreement (the “Senior Forbearance Agreement”) with Union Bank, N.A. (“UBNA”) and Natixis relating to existing and potential defaults under the ARCA dated December 17, 2008 among Cano, UBNA and Natixis 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”).

On September 24, 2010, our lenders delivered Reservation of Rights Letters (“Letters”), subsequently updated on January 5, 2011, specifying that we failed to timely comply with the material terms of the Forbearance Agreements and therefore terminated the Forbearance Agreements.  As of May 16, 2011, the lenders have taken no action with the delivery of these Letters.  We have recorded all additional interest and fees due under the terms of the Credit Agreements of $2.5 million in accrued liabilities on our consolidated balance sheet and in interest expense on consolidated statement of operations as of March 31, 2011.  We have also recorded additional interest expense associated with the accelerated amortization of deferred financing costs of $0.6 million applicable to the Credit Agreements, and accounting and legal expense incurred by our lenders of $0.6 million.

4. PREFERRED STOCK

On August 5, 2010, we entered into Forbearance Agreements with the lenders under our Credit Agreements that prohibited us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Preferred Stock. As discussed under Note 3, the Forbearance Agreements were terminated.  As of March 31, 2011, we have not remitted cash dividend payments for the Preferred Stock of $0.6 million for the nine-month period ended March 31, 2011. As of March 31, 2011, the unpaid cash dividend of $0.6 million is included in accrued liabilities reported in our consolidated balance sheets. Due to the non-payment of the cash dividends, along with the fact that the Preferred Stock is redeemable for cash as of September 6, 2011, our Preferred Stock has been reclassified from Temporary Equity to a current liability of $28.2 million on our consolidated balance sheet, which is the liquidation preference of $28.9 million less unamortized issuance costs of $0.7 million, which is presented as a discount on the consolidated balance sheet as of March 31, 2011.  During the three-month and nine-month periods ended March 31, 2011, issuance costs of $0.4 million and $0.8 million, respectively, were amortized in preferred stock dividend.

S. Jeffrey Johnson, our former Chief Executive Officer and former Chairman of our board of directors, owns approximately 3.5% of our outstanding Preferred Stock. For the three-month and nine-month periods ended March 31, 2010, we paid preferred dividend payments to Mr. Johnson of approximately $20,000and $59,000, respectively.  For the nine-month period ended March 31, 2011, we made no preferred dividend payments to Mr. Johnson.

On September 6, 2011, we are required to redeem the Preferred Stock for a redemption amount in cash equal to the stated value of the Preferred Stock, plus accrued cash and paid-in-kind dividends.  If we do not redeem the Preferred Stock (including accrued cash and paid-in-kind dividends) for cash on September 6, 2011, the redemption value of the Preferred Stock will accrue interest at 1.5% per month until Cano has redeemed the Preferred Stock.

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The subordination provisions of the Certificate of Designations of our Preferred Stock prohibit us from redeeming any of the Preferred Stock on September 6, 2011, if there are outstanding amounts due under our senior and subordinated credit agreements.

5. DERIVATIVES

Our derivatives consist of commodity derivatives and an interest rate swap arrangement, which are discussed in greater detail below.

Commodity Derivatives

Pursuant to the ARCA and SCA discussed in Note 3, we are required to maintain our existing commodity derivative contracts.  We entered into commodity derivative contracts to partially mitigate the risk associated with extreme fluctuations of prices for our crude oil and natural gas sales.  We have no obligation to enter into commodity derivative contracts in the future. Should we choose to enter into commodity derivative contracts to mitigate future price risk, we cannot enter into contracts for greater than 85% of our crude oil and natural gas production volumes attributable to proved producing reserves for a given month. As of March 31, 2011, our “collar” commodity derivative contracts with UBNA expired.  UBNA is one of the senior lenders under the ARCA.

On September 11, 2009, we entered into two fixed price commodity swap contracts with Natixis as our counterparty, which is one of our senior lenders under the ARCA. The fixed price swaps are based on West Texas Intermediate NYMEX prices and are summarized in the table below.

Interest Rate Swap Agreement

On January 12, 2009, we entered into a three-year LIBOR interest rate basis swap contract with Natixis Financial Products, Inc. (“Natixis FPI”) for $20.0 million in notional exposure. We entered into the interest rate swap agreement to partially mitigate the risk associated with rising interest rates.  Under the terms of the transaction, we will pay Natixis FPI, in three-month intervals, a fixed rate of 1.73% and Natixis FPI will pay Cano the prevailing three-month LIBOR rate.

Financial Statement Impact

During the three-month and nine-month periods ended March 31, 2011 and 2010, respectively, the gain (loss) on derivatives reported is reported in a separate caption on our consolidated statements of operations and is summarized as follows:

On August 10, 2010, we sold certain natural gas commodity derivative contracts realizing net proceeds of $0.8 million pursuant to the Forbearance Agreements. The cash settlements received/accrued by us under commodity derivatives were cumulative monthly payments due to us since the NYMEX natural gas and crude oil prices were lower than the floor prices set for the respective time periods and realized gains from the sale of uncovered “floor price” contracts as previously discussed. The cash settlements paid/accrued by us under commodity derivatives were cumulative monthly payments due to our counterparty since the NYMEX crude oil and natural gas prices were higher than the ceiling prices set for the respective time periods. The cash settlements paid/accrued by

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us under the interest rate swap were quarterly payments to our counterparty since the actual three-month LIBOR interest rate was lower than the fixed 1.73% rate we pay to the counterparty. The cash flows relating to the derivative instrument settlements that are due, but not cash settled are reflected in operating activities on our consolidated statements of cash flows as changes to current assets and current liabilities. At June 30, 2010, we had recorded a receivable from our counterparty included in accounts receivable on our consolidated balance sheet of $0.3 million. At March 31, 2011, we had no receivables due from our counterparty.

The unrealized gain (loss) on commodity derivatives represents estimated future settlements under our commodity derivatives and is based on mark-to-market valuation based on assumptions of forward prices, volatility and the time value of money as discussed below. We compared our internally derived valuation to our counterparties’ independently derived valuation to further validate our mark-to-market valuation.

The unrealized gain (loss) on interest rate swap represents estimated future settlements under our interest rate swap agreement and is based on a mark-to-market valuation based on assumptions of interest rates, volatility and the time value of money as discussed below.

Fair Value Measurements

Our assets and liabilities recorded at fair value are categorized based upon the level of judgment associated with the inputs used to measure their fair value. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.

Level 3—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

The fair value of our derivative contracts are measured using Level 2 and Level 3 inputs. The Level 3 input pertained to the subjective valuation for the effect of our own credit risk, which was significant to the fair value of the crude oil swap derivative contracts. The fair value of our commodity derivative contracts and interest rate swap are measured using Level 2 inputs based on the hierarchies previously discussed.

The estimated fair value of derivatives included in the consolidated balance sheet at March 31, 2011 is summarized below.

The following table shows the reconciliation of changes in the fair value of the net derivative assets classified as Level 2 and 3, respectively, in the fair value hierarchy for the nine months ended March 31, 2011 (in thousands).

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The change from net derivative assets of $1.2 million at June 30, 2010 to net derivative liabilities of $12.5 million at March 31, 2011 is attributable to the increases in crude oil and natural gas futures prices and settlements that occurred during the nine-month period. These amounts are based on our mark-to-market valuation of these derivatives at March 31, 2011 and may not be indicative of actual future cash settlements.

The following table summarizes the fair value of our derivative contracts as of the dates indicated:

6. DISCONTINUED OPERATIONS

On January 27, 2010, we completed the sale of our interests in certain oil and gas properties located in the Texas Panhandle (“Certain Panhandle Properties”) for net proceeds of $6.3 million, subject to customary post-closing adjustments. The sale had an effective date of January 1, 2010. The operating results of the Certain Panhandle Properties for the three-month and nine-month periods ended March 31, 2010 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below (in thousands).

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Interest expense, net of interest income, was allocated to discontinued operations based on the percent of operating revenues applicable to discontinued operations to the total operating revenues.

7. STOCK OPTIONS

During the nine-month period ended March 31, 2011, we did not grant additional stock options.  A summary of outstanding options as of March 31, 2011 is as follows:

Based on our $0.53 stock price at March 31, 2011, the intrinsic value of both the options outstanding and exercisable was approximately $21,000.

Total options exercisable at March 31, 2011 amounted to 930,780 shares and had a weighted average exercise price of $4.25. Upon exercise, we issue the full amount of shares exercisable per the term of the options from new shares. We have no plans to repurchase those shares in the future.

For the three-month period ended March 31, 2011, stock-based compensation expense was insignificant.  For the nine-month period ended March 31, 2011, we recorded a credit to stock-based compensation expense of $0.1 million, primarily due to award forfeitures. For the three- and nine-month periods ended March 31, 2010, we recorded a charge to stock-based compensation expense of $0.1 million and $0.2 million, respectively.  As of March 31, 2011, we had fully expensed the total compensation cost related to the outstanding option awards.

8. DEFERRED COMPENSATION

As of March 31, 2011, we had non-vested share awards totaling 10,000 shares to an employee pursuant to our 2005 Long-Term Incentive Plan, as summarized below:

The share awards will vest to the employee by July 2, 2011. The fair values of the awards are based on our actual stock price on the date of grant multiplied by the number of shares granted.  For the three-and nine-month periods ended March 31, 2011, we recorded a credit to stock-based compensation expense of $0.3 million for each period, primarily due to award forfeitures. For the three- and nine-month periods ended March 31, 2010, we expensed $0.2 million and $0.8 million, respectively, to stock-based compensation expense based on amortizing the fair value over the appropriate service period.  The forfeitures resulted from shares used to satisfy employees’ tax withholding obligations related to the vesting of their share awards and employee termination.

9. NET LOSS PER COMMON SHARE

Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding. Diluted net loss per common share is computed in the same manner, but also considers the effect of common stock shares underlying stock options, the preferred stock and paid-in-kind (“PIK”) dividends on an “as-converted” basis.

Shares of common stock underlying the following items were not included in dilutive weighted average shares outstanding for the three- and nine-month periods ended March  31, 2011 and 2010, as their effects would have been anti-dilutive.

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10. COMMITMENTS AND CONTINGENCIES

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., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. The plaintiffs claimed 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) alleged negligence and gross negligence and (ii) sought 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 sought (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 claimed that Cano and its subsidiaries were 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, Cano 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.

This lawsuit was resolved through a Settlement and Release Agreement effective October 19, 2010, pursuant to which this lawsuit has been dismissed without prejudice. The dismissal without prejudice will automatically convert to a dismissal with prejudice, thus foreclosing the plaintiffs’ ability to re-file this suit, once we have fully satisfied the obligations contained in the Settlement and Release Agreement.  Based on our knowledge and judgment of the facts as of February 14, 2011, our financial statements dated December 31, 2010 present fairly the effect of the actual and the anticipated future costs to resolve this matter.

Securities Litigation against Certain Former and Current 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 former Senior Vice President and Chief Financial Officer, Ben Daitch, Cano’s current Senior Vice President and Chief Financial Officer, Michael Ricketts and Cano’s former Senior Vice President of Engineering and Operations, Patrick McKinney, and

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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 sought 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 relief could be granted, and thus found merit in dismissing the lawsuit.

Resaca Claim

Section 7.6 of the Merger Agreement with Resaca Exploitation, Inc. (“Resaca”) provided for the Company and Resaca to share transaction expenses related to the printing, filing and mailing of the registration statement on Form S-4 covering the Resaca shares that would have been issued to Cano stockholders in the merger, the proxy statements relating to the meetings at which the stockholders of Cano and Resaca voted to approve the merger, 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.  On December 16, 2010, the presiding District Court judge denied Resaca’s request to transfer the venue.  On January 19, 2011, Resaca filed a motion for Partial Summary Judgment to seek reimbursement of certain merger-related expenses totaling $1.1 million, for which Cano’s 50% portion would be $0.5 million.  On April 14, 2011, the presiding judge denied Resaca’s request for Partial Summary Judgment. Based on our knowledge and judgment of the facts as of May 13, 2011, our financial statements dated March 31, 2011 present fairly the effect of the actual and the anticipated future costs to resolve this matter.

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.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. This Act provides a “safe harbor” for forward-looking statements to encourage companies to provide prospective information about themselves provided they identify these statements as forward looking and provide meaningful cautionary statements identifying important factors that could cause actual results to differ from the projected results. All statements other than statements of historical fact made in this report are forward looking. In particular, the statements herein regarding industry prospects and future results of operations or financial position are forward-looking statements. Forward-looking statements reflect management’s current expectations and are inherently uncertain. Our actual results may differ significantly from management’s expectations as a result of many factors, including, but not limited to, our ability to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our lenders, raise new capital, restructure the terms of our Preferred Stock, the volatility in prices for crude oil and natural gas, future commodity prices for derivative hedging contracts, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market competition, interruption in production, our ability to obtain additional capital, and the success of waterflooding and enhanced oil recovery techniques.

Statements in this Quarterly Report on Form 10-Q regarding Cano’s strategy, risk factors, capital budget, projected expenditures, liquidity and capital resources, and drilling and development plans reflect Cano’s current plans for the fiscal year ending June 30, 2011 as a stand-alone entity and do not take into account the impact of strategic alternatives being considered by Cano operating on a going concern basis.

You should read the following discussion and analysis in conjunction with the consolidated financial statements of Cano and its subsidiaries and notes thereto, included herewith. This discussion should not be construed to imply that the results discussed herein

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will necessarily continue into the future, or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment of management.

Overview

Introduction

We are an independent oil and natural gas company. Our strategy is to convert our proved undeveloped reserves into proved producing reserves, improve operational efficiencies in our existing properties and acquire accretive proved producing assets.  We intend to manage our assets as both an operator and non-operated participation. We expect to seek joint venture partners to exploit proved undeveloped reserves at some of our existing properties. Our assets are located onshore in the U.S. in Texas, New Mexico and Oklahoma.

Operating Activities Update

For the quarter ended March 31, 2011 (“current quarter”), our production averaged 907 net barrels of oil equivalent per day (BOEPD) as compared to production of 1,085 BOEPD for the quarter ended March 31, 2010 (“prior year quarter”). For the nine-month period ended March 31, 2011 (“current nine months”) our production averaged 988 BOEPD as compared to production of 1,086 BOEPD for the nine months ended March 31, 2010 (“prior year nine months”). For both the current quarter and the current nine-month period, we had production increases from the workover activities, behind-pipe recompletions in the Atoka Formation and return-to-production (“RTP”) program at the Desdemona Properties. These increases were more than offset by decreased production at the Cato and Panhandle Properties, which is further discussed below.

For the current quarter and current nine months, we incurred development capital expenditures of $0.1 million and $1.2 million, respectively, (excludes capitalized general and administrative and interest expenses). We have limited funds available for capital expenditures since we currently have no available borrowing capacity under our senior and subordinated credit agreements, and have very limited access to additional capital.

For March 2011, our production averaged 970 BOEPD.  The following is a discussion of our field level activity during the nine-month period ended March 31, 2011.

Cato Properties.  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 injection wells.  On August 5, 2010, we received an expansion permit from the NMOGCD to further expand the waterflood operations. As a result, we have increased water injection rates at Phase 1 project at the Cato Properties covering 1,000 acres.

During mid-October 2010, production was adversely affected by a weather-related electrical outage.  Production was shut-in for 30 days, which resulted in lost production of 75 BOEPD during the quarter ended December 31, 2010. During the outage, we installed larger electric submersible pumps (“ESP’s”) in both existing and RTP wells, and implemented necessary facility upgrades to optimize our infrastructure.  Our current configuration will be adequate for the Phase 1 waterflood project. As of March 31, 2011, we had increased our injection rate to 20,000 barrels of water injected per day (“BWIPD”), which is 6,500 BWIPD higher than the injection rate of 13,500 BWIPD at December 31, 2010.  We have seen increased fluid production rates and corresponding increasing crude oil rates as a direct result of this work.  During March 2011, our production averaged 194 BOEPD.  Our current injection rates approximate our anticipated requirement for the entire Phase 1 project.  We expect continued production improvements from the waterflood operations.  We have postponed our plans to develop proved developed non-producing reserves in the Queen Sands formation.

Davenport Properties.  Net production for the current quarter and current nine months was 71 BOEPD and 80 BOEPD, respectively. Net production for the prior year quarter and prior year nine months was 78 BOEPD and 75 BOEPD, respectively.  We are currently assessing the economic feasibility of an RTP project to activate non-producing wells.  During March 2011, our production averaged 72 BOEPD.

Desdemona Properties.  During the current nine months, we activated RTP wells and completed upgrades to our gas plant to sell all natural gas and natural gas liquids produced from the Duke Sand formation and new production from behind-pipe completions in the Atoka formation. Through December 31, 2010, we had returned to production 10 wells in the Duke Sand formation and recompleted two wells in the Atoka formation.  Each Atoka well recompletion had initial production of 125 mcfpd (21 BOEPD) and stabilized at 45-50 mcfpd (6 BOEPD). During March 2011, our production averaged 65 BOEPD.  We are currently assessing the economic feasibility of activating additional RTP wells as funds become available.

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Nowata Properties.  We are currently assessing the viability of increasing production by expanding the gas gathering system to connect additional wells to increase casinghead gas sales and optimizing current infrastructure.  During March 2011, our production averaged 225 BOEPD at the Nowata Properties, and has remained relatively flat since its acquisition in September 2004.

Panhandle Properties.  During the quarter ended September 30, 2010, we reduced the rate of waterflood injection at the Cockrell Ranch unit to optimize crude oil production and gain improved operational efficiencies.  Although this resulted in lost production of 30 BOEPD, operating margins have improved.  Our natural gas production decreases for both the current quarter and current nine-month period resulted from gas plant outages by DCP Midstream, L.P., which adversely impacted our production by 60 BOEPD, and inclement weather during the current quarter, which temporarily curtailed production.  During March 2011, our production averaged 413 BOEPD.

Liquidity and Capital Resources

At March 31, 2011, we had cash and cash equivalents of $1.1 million. We had negative working capital of $103.0 million, which included current liabilities of $66.5 million of long-term debt and $28.2 million of Series D convertible preferred stock. For the current nine months, we had cash flows provided by operations of $2.1 million, which is an improvement of $3.2 million as compared to the prior year nine months.

We are reviewing strategic alternatives, which include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, potential business combinations, debt restructuring, including possible bankruptcy and/or recapitalizing the Company. We continue to focus on cost reduction efforts to improve both our profitability and cash flow from operations.

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. The Consent and Forbearance Agreements were terminated as our lenders delivered Reservation of Rights Letters dated September 24, 2010 and January 5, 2011, as discussed in Note 3.  We continue to work with our lenders and advisors as we consider strategic alternatives.  As of May 13, 2011, our lenders have taken no definitive actions associated with the termination of the Consent and Forbearance Agreements.  We currently have no available borrowing capacity under our senior and subordinated credit agreements, and have very limited access to additional capital.

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. There is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded, or that the Company can continue to prepare future financial statements on a going concern basis. The ability of the Company to continue as a going concern will be dependent upon the outcome of our strategic alternatives review, crude oil and natural gas prices, sufficient liquidity to fund operations, actions by our lenders, mechanical problems at our wells and/or catastrophic events such as fires, hurricanes and flood.

In our areas of operation, we are subject to periodic review by federal and state authorities to ensure we can finance the eventual plugging and abandoning (“P&A”) of inactive wells.  Due to our current liquidity constraints, an acceleration of the P&A requirements could have an adverse impact to our operations.

Effective April 1, 2011, we are subject to fixed price commodity swap contracts that fix the price we received for crude oil production of 700 barrels per day, based on West Texas Intermediate NYMEX prices at $75.90 from April 1, 2011 to December 31, 2011, and $77.25 for calendar year of 2012.  Since we will not benefit from NYMEX prices in excess of the fixed prices, this could adversely impact our operations and/or adversely affect our ability to pay our counterparty.

Under both the ARCA and SCA, we were not in compliance with the covenants relating to our current ratio, leverage ratio and interest coverage ratio for the quarter ended March 31, 2011.  We have not made any borrowings since July 2010.  We continue to make our interest payments timely to the lenders.

Results of Operations

Overall

For the current quarter, we had a loss applicable to common stock of $5.2 million.  We had a loss applicable to common stock of $0.2 million for the prior year quarter. Items that positively impacted the current quarter were lower operating expenses of $2.6 million and increased operating revenues of $0.9 million.  These items were more than offset by increased loss on derivatives of $6.2 million, lower income from discontinued operations of $1.7 million, higher loss on sales of oil and gas properties of $1.0 million, increased interest expense of $0.9 million and increased preferred stock dividend of $0.4 million.

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For the current nine months, we had a loss applicable to common stock of $14.8 million.  We had a loss applicable to common stock of $13.1 million for the prior year nine months. Items that positively impacted the current nine months were lower operating expenses of $11.6 million and increased operating revenues of $2.2 million.  These items were more than offset by increased loss on derivatives of $7.2 million, increased interest expense of $4.3 million, lower income from discontinued operations of $2.1 million, higher loss on sales of oil and gas properties of $1.0 million and increased preferred stock dividend of $0.9 million.

These items will be further addressed in the following discussion.

Operating Revenues

The table below summarizes our operating revenues for the three- and nine-month periods ended March 31, 2011 and 2010.

(a)          As discussed in Note 5 to our Consolidated Financial Statements, on August 10, 2010, we sold certain natural gas commodity derivative contracts realizing net proceeds of $0.8 million pursuant to the Forbearance Agreement. The $0.8 million is excluded from the commodity derivative settlements listed above.

The current quarter operating revenues of $6.7 million represent an increase of $0.9 million as compared to the prior year quarter of $5.8 million. Higher average prices received for crude oil sales which increased operating revenues by $1.0 million and increased natural gas sales volumes of $0.3 million, were partially offset by lower crude oil volumes which reduced operating revenues by $0.4 million.

The current nine months operating revenues of $18.6 million are $2.2 million higher as compared to the prior year nine months of $16.4 million. The $2.2 million increase is primarily attributable to higher average prices received for crude oil and natural gas sales of $2.3 million and $0.5 million, respectively, and increased natural gas sales volumes of $0.1 million, partially offset by lower crude oil sales volumes which reduced operating revenues by $0.7 million.

Crude Oil Sales.  Our current quarter crude oil sales were 6 MBbls lower as compared to the prior year quarter.  The overall sales decrease resulted primarily from reduced combined sales at our Cato and Panhandle Properties of 8 MBbls, partially offset by increased production at our Desdemona Properties, which increased crude oil sales by 2 MBbls.  The changes to the sales of our individual properties are further discussed under “Overview-Operating Activities Update.”

Our current nine months crude oil sales were 11 MBbls lower as compared to the prior year nine months.  The overall sales decrease resulted primarily from reduced sales at our Cato Properties of 17 MBbls.  Partially offsetting the sales decrease were increased combined sales at the Desdemona and Davenport Properties of 6 MBbls.  The changes to the sales of our individual properties are further discussed under “Overview-Operating Activities Update.”

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Natural Gas Sales.  Our current quarter natural gas sales were 30 MMcf higher as compared to the prior year quarter.  The overall sales increase is primarily due to the higher sales at the Desdemona and Cato Properties of 18 MMcf and 11 MMcf, respectively. The increased natural gas sales at the Desdemona Properties are due to the RTP project as further discussed under “Overview-Operating Activities Update.”  The increased natural gas sales at the Cato Properties resulted from the natural gas purchaser temporarily declining to take Cato’s natural gas production for most of the prior year quarter.

Our current nine months natural gas sales were 23 MMcf higher as compared to the prior year nine months.  The overall sales increase is attributed to higher sales at our Desdemona Properties of 46 MMcf, partially offset by lower sales at the Panhandle and Cato Properties of 18 MMcf and 5 MMcf, respectively. The changes to the sales of our individual properties are further discussed under “Overview-Operating Activities Update.”

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 lower gravity of the crude oil and transportation expenses. 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. For the current quarter and current nine months, our average price received for crude oil sales was $89.26 and $79.32, respectively.  For the current quarter and current nine months, our average price received for natural gas sales was $9.69 and $8.53, respectively.

The average prices we received for our crude oil and natural gas sales were supplemented by commodity derivative settlements received for the current and prior year quarters.  As discussed in Note 5 to our Consolidated Financial Statements, if crude oil and natural gas NYMEX prices are lower than the “fixed prices,” we will be reimbursed by our counterparty for the difference between the NYMEX price and “fixed price” (i.e. realized gain).  Conversely, if crude oil and natural gas NYMEX prices are higher than the derivative “fixed prices,” we will pay our counterparty for the difference between the NYMEX price and “fixed price” (i.e. realized loss).

Operating Expenses

For the current quarter, our total operating expenses were $5.6 million, or $2.6 million lower than the prior year quarter of $8.2 million.  This was primarily due to lower general and administrative expenses of $1.6 million and reduced lease operating expenses of $1.1 million.

For the current nine months, our total operating expenses were $20.0 million, or $11.6 million lower than the prior year nine months of $31.6 million. This was primarily due to lower exploration expenses of $5.0 million, lower general and administrative expenses of $3.9 million and reduced lease operating expenses of $2.6 million.

These items are discussed in greater detail below.

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 current quarter, our LOE was $2.5 million, which was $1.1 million lower than the prior year quarter of $3.6 million. The $1.1 million decrease resulted primarily from reduced service rates negotiated with vendors and improved operating efficiencies, which led to decreased workover expenses of $0.2 million, lower chemical treatments of $0.2 million, decreased repairs of $0.1 million, lower labor expenses of $0.1 million and other expense reductions of $0.2 million, and a net insurance reimbursement of $0.3 million.  During the current quarter, we had a credit to expense for costs to restore production facilities of $0.3 million due to the $0.5 million insurance claim settlement partially offset by $0.2 million of costs incurred to restore the facilities.