UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

(Mark One)

For the transition period from              to            

Commission file number 001-32496

CANO PETROLEUM, INC.

(Exact name of small business issuer as specified in its charter)

The Oil & Gas Commerce Building

309 West 7^th Street, Suite 1600

Fort Worth, TX 76102

(Address of principal executive offices)

(817) 698-0900

(Issuer’s telephone number)

Not Applicable

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

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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  ý    No  o

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

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEDING FIVE YEARS

Check whether the registrant filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Exchange Act after the distribution of securities under a plan confirmed by a court. Yes  o     No  o

APPLICABLE ONLY TO CORPORATE ISSUERS

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date:  26,832,158 shares of common stock, $.0001 par value per share, as of May 2, 2006.

Transitional Small Business Disclosure Format (Check one): Yes  o     No  ý

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

CANO PETROLEUM, INC.
CONSOLIDATED BALANCE SHEET

March 31, 2006
(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.

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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 FINANCIAL STATEMENTS

1.              BASIS OF PRESENTATION AND USE OF ESTIMATES

The interim consolidated financial statements of Cano Petroleum, Inc. 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. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part to the volatility in prices for crude oil and natural gas, the timing of acquisitions, product demand, market competition, interruption in production, 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 Cano’s Form 10-KSB dated June 30, 2005.

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 oil and gas reserves, which may affect the amount at which oil and gas properties are recorded. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

2.              ACQUISITION OF W.O. ENERGY COMPANY OF NEVADA, INC.

On November 29, 2005, we acquired all of the outstanding common stock of W.O. Energy of Nevada, Inc. (“WO Energy”) for approximately $57.4 million, after purchase price adjustments. The purchase price consisted of approximately $48.3 million in cash (net of cash acquired) and approximately $8.24 million in restricted shares of our common stock.  $2 million of the cash portion of the purchase price was paid into an escrow account for a minimum of two years to cover potential indemnification payments by the sellers. The approximate $8.24 million of common stock resulted in the issuance of 1,791,320 shares to the sellers based on the average of the closing price of the common stock on AMEX for the three trading days immediately prior to November 29, 2005, which was $4.60 per share. We entered into a registration rights agreement with the sellers pursuant to which we agreed to use commercially reasonable efforts to register the resale of the 1,791,320 shares with the Securities and Exchange Commission by November 29, 2006. The sellers are prohibited from selling their shares until November 29, 2006 and after such date are limited to selling up to 15% of the shares received in any 90 day period.

 The WO Energy acquisition was recorded based on the purchase method of accounting. The operations of WO Energy are included in our consolidated financial statements beginning December 1, 2005. The purchase price were allocated to the acquired assets and assumed liabilities based on their estimated fair values. The calculation of the purchase price and allocation to assets is as follows:

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The fair value assigned to the oil and gas properties is based on management’s valuation of the properties, which was derived in part by reference to reserve reports prepared by an independent petroleum engineering firm. Based on the engineer’s reports and Cano’s internal analyses, we believe the value assigned to these properties is reasonably supported. We are continuing the process of determining our final estimate of fair value of assets and liabilities.

The acquisition was not eligible for Section 338 treatment. As defined in the Internal Revenue Service tax code, Section 338 treatment would have enabled us to recognize the stepped-up basis in the WO properties approximately equal to the acquisition price, for tax computation purposes. Therefore, we recorded a deferred tax liability of approximately $31.3 million (with an offsetting increase in property basis) in connection with this purchase.

The following condensed pro forma information gives effect to the acquisition as if it had occurred on July 1, 2005 and 2004, respectively. The pro forma information has been included in the Notes to financial statements as required by generally accepted accounting principles and is provided for comparison purposes only. The pro forma financial information is not necessarily indicative of the financial results that would have occurred had the business combination been effective on the dates indicated and should not be viewed as indicative of operations in the future.

Cano Petroleum, Inc.

Pro Forma Information

3.              LONG-TERM DEBT

Senior Credit Agreement

On November 29, 2005, we entered into a $100 million senior credit agreement with the lenders thereto from time to time and Union Bank of California, N.A., as administrative agent and as issuing lender, due on or before November 29, 2009. The initial borrowing base is $30 million based on our proved reserves. The $30 million was used, in part, to finance the acquisition of WO Energy. Pursuant to the terms of the senior credit agreement, the borrowing base is based on our proved reserves and is redetermined every six months with one additional redetermination possible during the six month periods between scheduled redeterminations. During the quarter ended March 31, 2006, Natexis Banques Populaires was named as a lender via an amendment to the senior credit facility.

At our option, interest is based either (i) on the prime rate plus the applicable margin ranging up to 0.75% based on the utilization level or (ii) on the LIBOR rate applicable to the interest period plus the applicable margin ranging from 1.5% to 2.25% based on the utilization level. At March 31, 2006, the interest rate was 7.08%. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.

At March 31, 2006, the outstanding amount due under the senior credit agreement was $27.75 million. The outstanding principal is due on or before November 29, 2009 unless pursuant to the terms

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of the credit agreement specific events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults by us, breaches of representations and warranties and covenants by us, our insolvency, a “change of control” of our business as described in the credit agreement and a “material adverse change” as described in the credit agreement.

The credit agreement imposes certain restrictions on us and our subsidiaries including, but not limited to, the following: (i) subject to specific exceptions, incurring additional liens; (ii) subject to specific exceptions, incurring additional debt; (iii) subject to specific exceptions, merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property; (iv) subject to specific exceptions, making certain payments, including cash dividends to our stockholders; (v) subject to specific exceptions, 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 interests in any person or any oil and gas properties or activities related to oil and gas properties unless with regard to new oil and gas properties, such properties are mortgaged to Union Bank of California, N.A., as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage in favor of Union Bank of California, N.A., as administrative agent; and (vi) subject to specific exceptions, entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.

We must also meet certain financial requirements based on specified debt coverage ratios, interest coverage ratios and current assets to current liabilities ratios. In addition, we are required to enter into financial contracts to hedge our exposure to commodity price risk associated with expected oil and gas production. Our financial hedge contracts are further discussed in Note 4.

As security for our obligations under the senior credit agreement: (i) each of our subsidiaries guaranteed all of our obligations; (ii) we, together with each of our subsidiaries, executed mortgages in favor of Union Bank of California, N.A., as collateral trustee, covering oil and gas properties located in Texas and Oklahoma; (iii) we, together with each of our subsidiaries, granted a security interest in favor of Union Bank of California, N.A., as collateral trustee, in substantially all of our assets; and (iv) we pledged our ownership interests in all of our subsidiaries to Union Bank of California, N.A., as collateral trustee.

Our senior credit agreement has been amended subsequent to March 31, 2006 and is further discussed in Note 13.

Subordinated Credit Agreement

On November 29, 2005, we entered into a $15 million subordinated credit agreement with the lenders thereto from time to time and Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio (“EEP”), as administrative agent, due on or before November 29, 2010. The $15 million was used, in part, to finance the acquisition of WO Energy.

Interest pursuant to the subordinated credit agreement is equal to the LIBOR rate plus 6.5%. At March 31, 2006, the interest rate was 11.24%. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.

As of March 31, 2006, the outstanding amount due under the subordinated credit agreement was $15 million. The outstanding principal is due on November 29, 2010 unless specified events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults by us, breaches of representations and warranties and covenants by us, our insolvency, a “change of control” of our business as described in the subordinated credit agreement and a “material adverse change” as described in the subordinated credit agreement.

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The subordinated credit agreement imposes certain restrictions on us and our subsidiaries including, but not limited to, the following: (i) subject to specific exceptions, incurring additional liens; (ii) subject to specific exceptions, incurring additional debt; (iii) subject to specific exceptions, merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property; (iv) subject to specific exceptions, making certain payments, including cash dividends to our stockholders; (v) subject to specific exceptions, 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 interests in any person or any oil and gas properties or activities related to oil and gas properties unless with regard to new oil and gas properties, such properties are mortgaged as requested by EEP, as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage as requested by of EEP, as administrative agent; and (vi) subject to specific exceptions, entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.

We must also meet certain financial requirements based on specified debt coverage ratios, interest coverage ratios, current assets to current liabilities ratios, and reserve value coverage. In addition, we are required to enter into financial contracts to hedge our exposure to commodity price risk associated with expected oil and gas production, as further discussed in Note 4.

As security for our obligations under the credit agreement: (i) each of our subsidiaries guaranteed all of our obligations; (ii) we, together with each of our subsidiaries, executed mortgages in favor of Union Bank of California, N.A., as collateral trustee, covering oil and gas properties located in Texas and Oklahoma; (iii) we, together with each of our subsidiaries, granted a security interest in favor of Union Bank of California, N.A., as collateral trustee, in substantially all of our assets; and (iv) we pledged our ownership interests in all of our subsidiaries to Union Bank of California, N.A., as collateral trustee.

Our subordinated credit agreement has been amended subsequent to March 31, 2006 and is further discussed in Note 13.

4.              DERIVATIVE HEDGING CONTRACTS

As previously mentioned in Note 3, pursuant to our senior and subordinated credit agreements, we are required to enter into financial contracts to hedge a portion of our production at specified prices for oil and natural gas. The objective of the hedging contracts is to reduce our exposure to commodity price risk associated with expected oil and gas production. By achieving this objective we intend to protect the outstanding debt amounts and maximize the funds available under our existing debt agreements, which should enable us to support our annual capital budgeting and expenditure plans.

During December 2005, we paid $5.3 million to enter into financial contracts to set price floors, as summarized in the table below.

We have no derivative hedging contracts that set a price ceiling. We do not designate our derivatives as cash flow or fair value hedges. However, we do not hold or issue derivative financial instruments for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparties to our financial hedging contracts. We anticipate, however, that such counterparties will be able to fully satisfy their obligations under the contracts. We do not obtain collateral or other security to support our financial hedging contracts subject to credit risk but we monitor the credit standing of the counterparties. At March 31, 2006, we had a receivable balance due from our counterparties amounting to $69,766.

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Changes in the fair values of our derivative instruments are recorded immediately in earnings in other income on our statements of operations. Cash flows resulting from the settlement of our derivative instruments are recorded as other income or expense in the consolidated statements of operations. During the three- and nine-month periods ended March 31, 2006, there were settlements under our derivative agreements due to Cano amounting to $140,996, which is included in our Consolidated Statements of Operations under “Crude oil and natural gas sales.”  The settlements were cumulative monthly payments due to Cano since the NYMEX gas price was lower than the $8.50 “floor gas price.”  The cash flows relating to the derivative instruments are reflected in operating activities on our statements of cash flow.

Our mark-to-market valuations used for our derivative instruments were based on prices that are actively quoted and provided by external sources. In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recorded the $5.3 million payment as Derivative Assets. SFAS 133 also provides that derivative instruments be measured at fair value on the balance sheet date.  During the three- and nine-month periods ended March 31, 2006, we recognized losses on hedge contracts to our Consolidated Statements of Operations amounting to $1.3 million and $2.9 million, respectively, under “Unrealized loss on hedge contracts.”  At March 31, 2006, our Derivative Assets totaled $2,407,273, of which $1,426,684 is considered long-term.

5.              COMMON STOCK FINANCINGS

As discussed in Note 2, we issued 1,791,320 shares of our common stock to complete the acquisition of WO Energy.

On September 14, 2005 and September 16, 2005, we received written commitments for two private placement sales of 2,603,864 shares and 2,100,000 shares, respectively, of our common stock at a per share price equal to $4.14, which was the closing price on September 13, 2005 on the American Stock Exchange. The gross and net proceeds totaled approximately $19.5 million and $18.3 million, respectively. The transactions closed on or before September 30, 2005.

The amount of common shares issued and outstanding is summarized as follows:

6.              ASSET RETIREMENT OBLIGATION

Our financial statements reflect the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Our asset retirement obligation (“ARO”) primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our ARO by calculating the present value of expected cash flows related to the liability. At March 31, 2006, our liability for ARO was $1,585,703, of which $1,566,261 is considered long-term. Our asset retirement obligations are recorded as current or non-current liabilities based on the estimated timing of the anticipated cash flows.

The following table describes the changes in our asset retirement obligations for the nine months ended March 31, 2006:

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7.              DEFERRED COMPENSATION

As discussed in our Form 10-KSB dated June 30, 2005, pursuant to the terms of the Merger Agreement dated May 28, 2004, eight individuals (six current employees, one former employee and one director) were issued 5,165,000 shares of common stock. These shares were placed in escrow and will vest to the individuals based on a combination of continued employment (“compensation shares”) and achieving certain performance goals during the two years following the merger (“performance shares”). The compensation shares amounted to 2,659,975 shares and the performance shares amounted to 2,505,025 shares. Any shares that are not released from escrow will be returned to Treasury Stock.

We accounted for these shares in accordance with the provisions of Statement of Financial Accounting Standard (“SFAS”) No. 123, Accounting for Stock-Based Compensation, and SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure. At the merger date, we recognized $2,324,250 of “Deferred Compensation” and “Additional Paid-in Capital” in the Consolidated Balance Sheet. The shares were recorded based on the quoted market price at the time of the transaction and are being amortized to expense over the periods earned. At March 31, 2006, the balance of Deferred Compensation was $97,972, net of amortization expense.

As of March 31, 2006, shares returned to treasury totaled 15,783 shares and are recorded as Treasury Stock, at cost. On July 1, 2005, the compensation shares totaling 2,505,025 shares were released from escrow to three executive officers. At March 31, 2006, the total escrowed shares were 2,659,975, of which the outstanding common shares totaled 2,644,192 and treasury shares totaled 15,783.

8.              STOCK OPTIONS

As discussed in our Form 10-KSB dated June 30, 2005, the 2005 Directors’ Stock Option Plan (“Plan”) became effective on April 1, 2005. On April 1, 2005, pursuant to the Plan, we granted stock options to our five non-employee directors to each purchase 25,000 shares of common stock. The options granted under the Plan totaled 125,000 shares. These options have an exercise price of $4.13 per share. The options vested on April 1, 2006, and expire on April 1, 2015.

On September 16, 2005, we granted stock options to James K. Teringo, Jr., our Vice President, General Counsel and Corporate Secretary to purchase 50,000 shares of common stock. These options have an exercise price of $3.98 per share. The options vest on July 11, 2006, and expire on September 16, 2015.

On December 7, 2005, our shareholders approved our 2005 Long-Term Incentive Plan (“LTIP”). The 2005 LTIP authorizes the issuance of up to 1,000,000 shares of our common stock to key employees, key consultants and outside directors of our company and subsidiaries. The 2005 LTIP permits the grant of incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, dividend equivalent rights and other awards, whether granted singly, or in combination or in tandem. No executive officer (as defined in the 2005 LTIP) may receive in any calendar year (i) stock options or stock appreciation rights relating to more than 100,000 shares of common stock or (ii) restricted stock, restricted stock units, performance awards or other awards that are subject to the attainment of performance goals relating to more than 100,000 shares of common stock; provided, however, that all such awards of any executive officer during any calendar year may not exceed an aggregate of more than 100,000 shares of common stock. The 2005 LTIP terminates on December 7, 2015; however, awards granted before that date will continue to be effective in accordance with their terms and conditions.

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On December 13, 2005, under the 2005 LTIP, 25,000 options were granted to each of our five non-employee Directors: Donnie D. Dent, Gerald W. Haddock, Randall Boyd, Dr. Jim Underwood and Morris B. “Sam” Smith. Each of these options has an exercise price of $6.30 per share. These granted options vest on December 13, 2006 if such persons are still directors on December 13, 2006.

Pursuant to Statement of Financial Accounting Standard No. 123 (“SFAS 123”), Accounting for Stock-Based Compensation, the fair value of each stock option is estimated on the date of grant using the Black-Scholes option-pricing model. The factors used to calculate the fair value of all options are summarized in the table below:

The total fair value of the options summarized in the above table is approximately $424,000. In accordance with the provisions of SFAS 123 and SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure, we have recorded a charge to general and administrative expenses for the estimated fair value of the options granted to our directors of $61,643 and $134,437 for the three- and nine-month periods ended March 31, 2006, respectively. For the three- and nine-month periods ended March 31, 2005, we charged $67,000 and $78,666, respectively.

9.              NET LOSS PER COMMON SHARE

Basic net income (loss) per common share is computed by dividing the net income attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period.

Diluted net income (loss) per common share is computed in the same manner, but also considers the effect of the stock options. The stock options are not considered for the three and nine months ended March 31, 2006 as their effects would be anti-dilutive.

The weighted average shares used in the basic loss per common share computations for the three and nine months ended March 31, 2006 were 24,187,966 shares and 21,740,759 shares, respectively.  The weighted average shares for the three and nine months ended March 31, 2005 were 11,204,155 shares and 10,722,854, respectively. The shares at March 31, 2006 and 2005 excluded contingently issuable shares of 2,659,975 and 5,165,000, respectively, as discussed in Note 7.

10.       RELATED PARTY TRANSACTIONS

As discussed in our Form 10-KSB dated June 30, 2005, on March 29,2005, we entered into an agreement with Haddock Enterprises, LLC and Kenneth Q. Carlile (predecessor to Carlile Management, LLC) to explore the possibility of converting the Sabine Royalty Trust from a liquidating asset into a vehicle to acquire low risk assets. Each of the three parties owns a one-third interest in the Sabine Production Operating, LLC. Gerald W. Haddock is President of Haddock Enterprises, LLC and is a member of our Board of Directors. As of March 31, 2006, Cano had incurred approximately $419,000 pertaining to the joint venture, of which $379,000 occurred during the nine months ended March 31, 2006. We expensed the $419,000 to general & administrative expense because of the election of Sabine Production Operating, LLC to indefinitely suspend the proxy solicitation from the unit holders of the Sabine Royalty Trust.

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Effective December 1, 2005, we acquired all overriding royalty interests held by THEprivate Energy Company, Inc. (formerly Cano Energy Corporation) on December 27, 2005 and we are to acquire all overriding royalty interests acquired in the future by THEprivate Energy Company, Inc. in and to the oil gas and mineral leaseholder estates and personal property related to leasehold estates located on the same property on which the Davenport Field Unit’s properties are located. We paid $66,700 per percentage of net revenue attributable to the interests held by THEprivate Energy Company, Inc. During December 2005, we paid $500,250 to acquire a 7.5% overriding royalty interest and during January 2006, we paid $200,100 to acquire a 3.0% overriding royalty interest.

S. Jeffrey Johnson, our Chairman of the Board and Chief Executive Officer, is a 30% shareholder in THEprivate Energy Company, Inc. The terms of the purchase were agreed to based on arms-length negotiations, supported by a valuation established by our independent engineer, and are substantially the same as previously paid by us to THEprivate Energy Company, Inc. for a portion of its interest in September and October of 2004. This purchase was approved by our Board pursuant to a recommendation by our Audit Committee.

11.       INCOME TAXES

Our income tax benefit is as follows:

The difference between our benefit from income taxes recorded on the statements of operations and the tax computed using statutory rates primarily comprises state taxes and adjustments to the valuation allowance.

Regarding the acquisition of Square One Energy, Inc., as discussed in our Form 10-KSB dated June 30, 2005, this acquisition did not provide for Section 338 treatment. As defined in the Internal Revenue Service tax code, Section 338 treatment would have enabled us to recognize the stepped-up basis in the Square One properties approximately equal to the acquisition price, for tax computation purposes.

In accordance with the purchase method of accounting, we recorded a deferred tax liability of approximately $3.1 million with an offsetting increase in property basis of $2.4 million and Goodwill of approximately $0.7 million. Based on a reserve report prepared by an independent petroleum engineering firm and our internal analysis, we believe the oil and gas properties of Square One have unrealized potential to support the recording of “Goodwill” to the Consolidated Balance Sheet.

 At March 31, 2006, we have recorded a total deferred tax liability of $33 million, which resulted from the acquisitions of WO Energy (see Note 2) and Square One, net of deferred income tax benefit

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of $1.4 million that we recorded during the nine months ended March 31, 2006. A schedule showing the significant components of the net deferred tax liability as of March 31, 2006 is as follows:

At March 31, 2006, Cano had net operating loss (“NOL”) carryforwards for tax purposes of approximately $11 million. The remaining net operating losses principally expire in 2024 and 2025. Of the $11 million, $2.2 million will be unavailable to offset any future taxable income due to limitations from change in ownership as defined in Section 382 of the Internal Revenue Service (“IRS”) code. Accordingly, our valuation allowance reflects the unavailable $2.2 million NOL.

12.       COMMITMENTS AND CONTINGENCIES

Litigation

On March 23, 2006, the following lawsuit was filed in the 100^th 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, Ltd, and W.O. Energy, Inc. The plaintiffs claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs (i) allege negligence and gross negligence and (ii) seek undisclosed 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. In addition, the plaintiffs seek (i) termination of certain oil and gas leases, (ii) reimbursement for their attorney’s fees and (iii) exemplary damages.

Due to the inherent risk of litigation and the fact that this case is in the early stages of discovery, the outcome of this case is uncertain and unpredictable; however, at this time Cano management believes the suit is without merit and is vigorously defending itself and its subsidiaries.

On April 28, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. There are 43 plaintiffs that claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs (i) allege negligence, gross negligence, trespass and nuisance and (ii) seek undisclosed damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses. In addition, the plaintiffs seek (i) reimbursement for their attorney’s fees and (ii) exemplary damages.

Due to the inherent risk of litigation and the fact that this case is in the early stages of discovery, the outcome of this case is uncertain and unpredictable; however, at this time Cano management believes the suit is without merit and is vigorously defending itself and its subsidiaries.

On April 10, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. On May 1, 2006, the

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following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1923, Chisum Family Partnership, Ltd. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. Although Cano is aware that these two lawsuits were filed, neither it nor any of its subsidiaries that are named in the lawsuits have been served with process. The plaintiffs in both cases claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs in both cases (i) allege negligence and trespass and (ii) seek undisclosed damages, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs in both cases seek (i) reimbursement for their attorney’s fees and (ii) exemplary damages.

Due to the inherent risks of litigation and the fact that neither Cano nor its subsidiaries have been served with these suits, the outcome of these cases is uncertain and unpredictable; however, at this time Cano management believes the suits are without merit and, if and when it is served, will vigorously defend itself and its subsidiaries.

Other

Occasionally, we are involved in other various 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, including due to the existence of insurance coverage, indemnification and escrow accounts, will have a material effect on our financial position or results of operations. None of our directors, officers or affiliates, owners of record or beneficially of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to our business or has a material interest adverse to our business.

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.

13.       SUBSEQUENT EVENTS

New Acquisition

On April 26, 2006, we entered into an Asset Purchase and Sale Agreement regarding the purchase and sale of oil and gas properties in the Panhandle Field located in Texas. The purchase price was $24 million in cash. The acquisition by our wholly-owned subsidiary, Pantwist, LLC, included two workover rigs and other equipment valued at approximately $1.25 million.

Financing

The aforementioned acquisition was funded pursuant to Amendment No. 2 to our existing senior credit facility, as described in Note 3. Pursuant to the Amendment, the borrowing base increased from $30 million to $55 million. Cano borrowed an additional $25 million under the senior credit facility to fund the aforementioned acquisition. As of April 28, 2006, this increased Cano’s total outstanding borrowings under the senior credit facility to $52.75 million with a blended interest rate of approximately 7.27% at May 4, 2006.

The terms of the Amendment (i) require a $5 million reduction of the borrowing base by December 31, 2006 and (ii) require that if as of the end of any fiscal quarter end occurring on or after June 30, 2006, the ratio of Cano’s consolidated debt to consolidated earnings before interest, taxes, depreciation and amortization exceeds 3.00 to 1.00, then on or prior to the following fiscal quarter end, Cano shall prepay advances or, if the advances have been repaid in full, make deposits as cash collateral to provide cash collateral for letter of credit exposure, in an amount equal to the greater of (a) $20 million and (b) an amount necessary to cause the ratio of Cano’s consolidated debt to

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consolidated earnings before interest, taxes, depreciation and amortization to be less than 3.00 to 1.00. In addition, we will hedge at least 50% of production attributable to the new acquisition for three years at “price floors” of $60 per barrel and $7.60 per mcf. Cano has implemented these “price floor” hedges and there is no “price ceiling” on the hedge.

Also, the Amendment requires that Cano will hedge or cause to be hedged between 50% and 80% of its existing production. Cano’s existing hedges, as discussed in Note 4, comply with this requirement.

Amendment to Senior Credit Agreement

Based on our financial position and results of operations for the quarter ended March 31, 2006, we were unable to comply with two covenants of the senior credit facility. As more fully described below, on May 12, 2006, but effective as of March 31, 2006, we entered into an amendment to the Senior Credit Agreement which allowed us, as of March 31, 2006, to comply with those two covenants, as amended.

On May 12, 2006, but effective as of March 31, 2006, Cano, its subsidiaries, Union Bank of California, N.A, (“Union Bank”) as Administrative Agent/Issuing Lender and Natexis Banques Populaires entered into Amendment No. 3 to the Credit Agreement dated November 29, 2005, as previously amended, by and among Cano, the lenders party thereto from time to time and Union Bank, as Administrative Agent and Issuing Lender (“Amendment to the Credit Agreement”). The Amendment to the Credit Agreement changes as of March 31, 2006 the Debt Coverage Ratio and the Interest Coverage Ratio.

In the Amendment to the Credit Agreement, the Debt Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated Debt (as defined in the Credit Agreement) of Cano for the quarter to the consolidated EBITDA, an acronym for net earnings plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges, of Cano for the quarter multiplied by four must not be greater than 7.50 to 1.00 rather than 5.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the two quarter period multiplied by two must not be greater than 5.25 to 1.00 rather than 4.50 to 1.00, (iii)  for the quarter ending September 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 must not be greater than 4.50 to 1.00 rather than 4.00 to 1.00, (iv) for the quarter ending December 31, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 4.00 to 1.00 rather than 3.50 to 1.00 and (v) for all quarters ending on or after March 31, 2007, the ratio of consolidated Debt of Cano for such quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 3.50 to 1.00 which is the same as it was in the Credit Agreement.

In the Amendment to the Credit Agreement, the Interest Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated EBITDA of Cano for the quarter multiplied by four to the consolidated Interest Expense (as defined in the Credit Agreement) of Cano for the quarter multiplied by four must be at least 1.50 to 1.00 rather than 2.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated EBITDA of Cano for the two quarter period multiplied by two to the consolidated Interest Expense of Cano for the two quarter period multiplied by two must be at least 1.75 to 1.00 rather than 2.00 to 1.00, (iii) for the quarter ending September 30, 2006, the ratio of consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 to the consolidated Interest Expense of Cano for the three quarter period multiplied by 4/3 must be at least 2.00 to 1.00 which is the same as it was in the Credit Agreement and (iv) for the quarter ending December 31, 2006 and all future quarters, the ratio of consolidated EBITDA of Cano for the four quarter period to the consolidated Interest Expense of Cano for the four quarter period must be at least 2.00 to 1.00 which is the same as it was in the Credit Agreement.

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Amendment to Subordinated Credit Agreement

Based on our financial position and results of operations for the quarter ended March 31, 2006, we were unable to comply with two covenants of our of the subordinated credit facility. As more fully described below, on May 12, 2006, but effective as of March 31, 2006, we entered into an amendment to the Subordinated Credit Agreement which allowed us, as of March 31, 2006, to comply with those two covenants, as amended.

On May 12, 2006, but effective as of March 31, 2006, Cano, its subsidiaries, the lenders and Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent (the “Administrative Agent”) entered into the Second Amendment to Subordinated Credit Agreement dated November 29, 2005, as previously amended, by and among Cano, the lenders party thereto from time to time and the Administrative Agent (“Amendment to the Subordinated Credit Agreement”). The Amendment to the Subordinated Credit Agreement changes as of March 31, 2006 the Debt Coverage Ratio and the Interest Coverage Ratio.

In the Amendment to the Subordinated Credit Agreement, the Debt Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated Debt (as defined in the Subordinated Credit Agreement) of Cano for the quarter to the consolidated EBITDA, an acronym for net earnings plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges, of Cano for the quarter multiplied by four must not be greater than 7.50 to 1.00 rather than 5.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the two quarter period multiplied by two must not be greater than 5.25 to 1.00 rather than 4.50 to 1.00, (iii)  for the quarter ending September 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 must not be greater than 4.50 to 1.00 rather than 4.00 to 1.00 and (iv) for the quarter ending on or after December 31, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 4.00 to 1.00 which is the same as it was in the Credit Agreement.

In the Amendment to the Subordinated Credit Agreement, the Interest Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated EBITDA of Cano for the quarter multiplied by four to the consolidated Interest Expense (as defined in the Subordinated Credit Agreement) of Cano for the quarter multiplied by four must be at least 1.50 to 1.00 rather than 2.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated EBITDA of Cano for the two quarter period multiplied by two to the consolidated Interest Expense of Cano for the two quarter period multiplied by two must be at least 1.75 to 1.00 rather than 2.00 to 1.00, (iii) for the quarter ending September 30, 2006, the ratio of consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 to the consolidated Interest Expense of Cano for the three quarter period multiplied by 4/3 must be at least 2.00 to 1.00 which is the same as it was in the Subordinated Credit Agreement and (iv) for the quarters ending December 31, 2006 and all future quarters, the ratio of consolidated EBITDA of Cano for the four quarter period to the consolidated Interest Expense of Cano for the four quarter period must be at least 2.00 to 1.00 which is the same as it was in the Subordinated Credit Agreement.

Amendment to Registration Rights Agreements

As discussed in Note 2, on November 29, 2005, in connection with the acquisition of W.O. Energy, Cano entered into Registration Rights Agreements (the “Registration Rights Agreements”) with both Miles O’Loughlin (“O’Loughlin”) and Scott White (“White”) regarding shares of Cano common stock that were issued to O’Loughlin and White in connection with their sale of W.O. Energy to Cano (the “Purchase Shares”). The Registration Rights Agreements contained a right that if Cano did not register the Purchase Shares with the Securities and Exchange Commission (the “SEC”) by November 29, 2006, O’Loughlin and White had the option to require Cano to purchase the Purchase Shares from them for the closing price of Cano common stock on November 29, 2005.

On May 12, 2006, but effective as of November 29, 2005, Cano amended the Registration Rights Agreements with the Estate of O’Loughlin and with White (the “Registration Rights Amendments”) in order to remove the right of the Estate of O’Loughlin and of White to require Cano to purchase the

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Purchase Shares if the Purchase Shares were not registered with the SEC by November 29, 2005. The Registration Rights Amendments provide that Cano will include the Purchase Shares on the next registration statement that Cano files that would permit the resale of the Purchase Shares.

Amendment to Stock Purchase Agreement

As discussed in Note 2, on November 29, 2005, Cano acquired W.O. Energy from O’Loughlin and White pursuant to a Stock Purchase Agreement dated November 29, 2005 (the “Stock Purchase Agreement”). The Stock Purchase Agreement provided that O’Loughlin and White could not sell the Purchase Shares until November 29, 2006 and with the restriction that on or after such date, they could sell up to 15% of their Purchase Shares in any 90 day period. On May 12, 2006, Cano and W.O. Energy entered into an amendment to the Stock Purchase Agreement (the “Stock Purchase Amendment”) with the Estate of O’Loughlin and with White which provides that subject to the limitation on selling only up to 15% of their Purchase Shares in any 90 day period, the Estate of O’Loughlin and White may sell the Purchase Shares at any time the shares are registered for resale or are exempt from registration.

Item 2. Management’s Discussion and Analysis or Plan of Operation

Forward-Looking Statements

The information in this report on Form 10-QSB 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, the volatility in prices for crude oil and natural gas, future commodity prices for derivative hedging contracts, the timing of acquisitions, our ability to obtain additional capital, product demand, market competition, interruption in production, transportation restrictions, interest rates, valuations of oil and gas reserves, drilling risks and the success of waterflooding and enhanced oil recovery techniques.

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

Overall Strategy

We are a growing independent oil and gas company that intends to actively utilize secondary and enhanced oil recovery (“EOR”) methods to increase production and reserves at our existing properties and future acquisitions. Our primary focus is crude oil and our target acquisitions are onshore U.S. properties. Our focus on domestic, mature oil fields eliminates exploration risks and logistical uncertainties inherent in international operations. We use secondary waterflooding and EOR methods, such as surfactant-polymer flooding technology.

We believe significant growth opportunities exist primarily because the major energy companies and large independents continue to focus their attention and resources toward the exploration and production of large fields. In the past several years, the major companies have been divesting themselves of their mature, smaller oil fields. During recent years, the energy industry has predominately focused on natural gas exploration and production, and has been significantly less focused on crude oil. The recent

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economics of the oil and gas market have improved as prices have risen substantially. These conditions provide ample opportunities for smaller independent companies to acquire and exploit mature U.S. oilfields. Our emphasis on EOR methods positions us in a unique niche segment in the oil and gas industry. Our acquisition targets are proven, mature oil fields that possess significant proved reserves, as well as a high ratio of probable reserves. We expect to encounter increased competition for such properties in the future.

Liquidity and Capital Resources

At March 31, 2006, our cash balance was $1.3 million and our available borrowing amount was $2 million under the senior credit agreement.  In addition, as discussed in Note 3, the senior credit agreement currently has a total commitment of $100 million, of which the borrowing base is $30 million as of March 31, 2006.  The senior agreement provides for semiannual redeterminations of the borrowing base amount and one additional redetermination during the six month periods.

We intend to finance future acquisitions of oil and gas properties, field development projects, operating activities and the potential payments under the senior credit agreement with a combination of issuances of equity, debt financing, and cash flow from operations.   The potential payments under the senior credit agreement pertain to Amendment No. 3, as discussed below under “Amendment to Senior Credit Agreement” and Amendment No. 2, as discussed below under “New Acquisition & Financing.” Pursuant to Amendment No. 3, we may be required to make a payment ranging up to $25 million as of June 30, 2006.  Pursuant to Amendment No. 2, we may be required to make a minimum $20 million payment by September 30, 2006.  We cannot guarantee that any additional equity or debt financing will be available in sufficient amounts or on acceptable terms when needed.  If such financing is not available in sufficient amounts or on acceptable terms, our results of operations and financial condition may be adversely affected.  In addition, equity financing may result in dilution to existing stockholders and may involve securities that have rights, preferences, or privileges that are senior to our common stock, and any debt financing obtained must be repaid regardless of whether or not we generate profits or cash flows from our business activities.

Financing and Investing Activities

During the nine months ended March 31, 2006, we completed the following capital financings:

•                  As discussed in Note 5 to the financial statements, we received net proceeds of $18.3 million from the issuance of 4,703,864 shares of common stock during September 2005.

•                  As discussed Note 3 to the financial statements, on November 29, 2005, we entered into a $100 million senior credit agreement. The initial borrowing base is $30 million based on our proved reserves, as identified in the table below. As of March 31, 2006, our borrowings under this agreement totaled $27.75 million and the available borrowing amount was $2 million.

•                  As discussed in Note 3 to the financial statements, on November 29, 2005, we entered into a $15 million subordinated credit agreement. As of March 31, 2006, our outstanding balance was $15 million under this agreement.

The net proceeds from these capital financings were used to finance the acquisition of WO Energy for approximately $57.4 million, as discussed in Note 2 to the financial statements, and the $5.3 million purchase of derivative hedging contracts, as discussed in Note 4 to the financial statements.

The primary asset of WO Energy is the Panhandle Field located in Texas. The acquisition of WO Energy was the primary reason our net oil and gas assets increased from $16.5 million as of September 30, 2005 to $106.5 million as of March 31, 2006. The Panhandle Field represents 34,497 MBOE of our total 47,178 MBOE proved reserves, as shown in the table in the “Proved Reserves” section below.

As discussed in Note 4 to the financial statements, pursuant to our senior and subordinated credit agreements, we are required to enter into financial contracts to hedge our exposure to commodity price risk associated with expected oil and gas production. For calendar years 2006, 2007, and 2008, the hedged production amounts, as expressed in barrels of oil equivalent per day, are 832, 781, and 735, respectively. We entered into financial contracts to set the following price floors for calendar years 2006 through 2008:

•                  Crude oil production of $60/barrel for 2006, and $55/barrel for 2007 and 2008.

•                  Natural gas production of $8.50/mcf, $8.00/mcf, and $7.50/mcf for 2006, 2007, and 2008, respectively.

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We have no derivative hedging contracts that set a price ceiling. Therefore, we are entitled to 100% of our revenue receipts and, if crude oil and natural gas NYMEX prices are lower than the price floor, we will be reimbursed for the difference between the NYMEX price and floor price.

New Acquisition & Financing

As discussed in Note 13, we acquired additional oil and gas properties in the Panhandle Field located in Texas. On April 28, 2006, Pantwist, LLC (“Pantwist”), a wholly owned subsidiary of Cano, acquired these oil and gas properties with an effective date of the acquisition of February 1, 2006. The purchase price was $24 million in cash, as adjusted. These oil and gas properties cover approximately 9,700 acres, currently produce approximately 400 net barrels of oil equivalent (“BOE”) per day and have approximately 7 million BOE of proved reserves, of which approximately 2.1 million BOE are proved producing reserves. The acquisition included two workover rigs and other equipment valued at approximately $1.25 million.

The acquisition was funded pursuant to Amendment No. 2 to our existing senior credit facility, as discussed in Note 3. Pursuant to the Amendment, the borrowing base increased from $30 million to $55 million. Cano borrowed an additional $25 million under the senior credit facility to fund the aforementioned acquisition. As of April 28, 2006, this increased Cano’s total outstanding borrowings under the senior credit facility to $52.75 million with a blended interest rate of approximately 7.27% at May 4, 2006.

The terms of the Amendment (i) require a $5 million reduction of the borrowing base by December 31, 2006 and (ii) require that if as of the end of any fiscal quarter end occurring on or after June 30, 2006, the ratio of Cano’s consolidated debt to consolidated earnings before interest, taxes, depreciation and amortization exceeds 3.00 to 1.00, then on or prior to the following fiscal quarter end, Cano shall prepay advances or, if the advances have been repaid in full, make deposits as cash collateral to provide cash collateral for letter of credit exposure, in an amount equal to the greater of (a) $20 million and (b) an amount necessary to cause the ratio of Cano’s consolidated debt to consolidated earnings before interest, taxes, depreciation and amortization to be less than 3.00 to 1.00. In addition, we will hedge at least 50% of production attributable to the new acquisition for three years at “price floors” of $60 per barrel and $7.60 per mcf. Cano has implemented these “price floor” hedges and there is no “price ceiling” on the hedge.

Also, the Amendment requires that Cano will hedge or cause to be hedged between 50% and 80% of its existing production. Cano’s existing hedges, as discussed in Note 4, comply with this requirement.

Amendment to Senior Credit Agreement

Based on our financial position and results of operations for the quarter ended March 31, 2006, we were unable to comply with two covenants of the senior credit facility. As more fully described below, on May 12, 2006, but effective as of March 31, 2006, we entered into an amendment to the Senior Credit Agreement which allowed us, as of March 31, 2006, to comply with those two covenants, as amended.

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On May 12, 2006, but effective as of March 31, 2006, Cano, its subsidiaries, Union Bank of California, N.A, (“Union Bank”) as Administrative Agent/Issuing Lender and Natexis Banques Populaires entered into Amendment No. 3 to the Credit Agreement dated November 29, 2005, as previously amended, by and among Cano, the lenders party thereto from time to time and Union Bank, as Administrative Agent and Issuing Lender (“Amendment to the Credit Agreement”). The Amendment to the Credit Agreement changes as of March 31, 2006 the Debt Coverage Ratio and the Interest Coverage Ratio.

In the Amendment to the Credit Agreement, the Debt Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated Debt (as defined in the Credit Agreement) of Cano for the quarter to the consolidated EBITDA, an acronym for net earnings plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges, of Cano for the quarter multiplied by four must not be greater than 7.50 to 1.00 rather than 5.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the two quarter period multiplied by two must not be greater than 5.25 to 1.00 rather than 4.50 to 1.00, (iii)  for the quarter ending September 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 must not be greater than 4.50 to 1.00 rather than 4.00 to 1.00, (iv) for the quarter ending December 31, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 4.00 to 1.00 rather than 3.50 to 1.00 and (v) for all quarters ending on or after March 31, 2007, the ratio of consolidated Debt of Cano for such quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 3.50 to 1.00 which is the same as it was in the Credit Agreement.

In the Amendment to the Credit Agreement, the Interest Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated EBITDA of Cano for the quarter multiplied by four to the consolidated Interest Expense (as defined in the Credit Agreement) of Cano for the quarter multiplied by four must be at least 1.50 to 1.00 rather than 2.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated EBITDA of Cano for the two quarter period multiplied by two to the consolidated Interest Expense of Cano for the two quarter period multiplied by two must be at least 1.75 to 1.00 rather than 2.00 to 1.00, (iii) for the quarter ending September 30, 2006, the ratio of consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 to the consolidated Interest Expense of Cano for the three quarter period multiplied by 4/3 must be at least 2.00 to 1.00 which is the same as it was in the Credit Agreement and (iv) for the quarter ending December 31, 2006 and all future quarters, the ratio of consolidated EBITDA of Cano for the four quarter period to the consolidated Interest Expense of Cano for the four quarter period must be at least 2.00 to 1.00 which is the same as it was in the Credit Agreement.

Amendment to Subordinated Credit Agreement

Based on our financial position and results of operations for the quarter ended March 31, 2006, we were unable to comply with two covenants of the subordinated credit facility. As more fully described below, on May 12, 2006, but effective as of March 31, 2006, we entered into an amendment to the Subordinated Credit Agreement which allowed us, as of March 31, 2006, to comply with those two covenants, as amended.

On May 12, 2006, but effective as of March 31, 2006, Cano, its subsidiaries, the lenders and Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent (the “Administrative Agent”) entered into the Second Amendment to Subordinated Credit Agreement dated November 29, 2005, as previously amended, by and among Cano, the lenders party thereto from time to time and the Administrative Agent (“Amendment to the Subordinated Credit Agreement”). The Amendment to the Subordinated Credit Agreement changes as of March 31, 2006 the Debt Coverage Ratio and the Interest Coverage Ratio.

In the Amendment to the Subordinated Credit Agreement, the Debt Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated Debt (as defined in the Subordinated Credit Agreement) of Cano for the quarter to the consolidated EBITDA (as defined in the Credit Agreement) of Cano for the quarter multiplied by four must not be greater than 7.50 to 1.00 rather than 5.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the two quarter period multiplied by two must not be

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greater than 5.25 to 1.00 rather than 4.50 to 1.00, (iii)  for the quarter ending September 30, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 must not be greater than 4.50 to 1.00 rather than 4.00 to 1.00 and (iv) for the quarter ending on or after December 31, 2006, the ratio of consolidated Debt of Cano for the quarter to the consolidated EBITDA of Cano for the four quarter period must not be greater than 4.00 to 1.00 which is the same as it was in the Credit Agreement.

In the Amendment to the Subordinated Credit Agreement, the Interest Coverage Ratio changed as follows:  (i) for the quarter ending March 31, 2006, the ratio of consolidated EBITDA of Cano for the quarter multiplied by four to the consolidated Interest Expense (as defined in the Subordinated Credit Agreement) of Cano for the quarter multiplied by four must be at least 1.50 to 1.00 rather than 2.00 to 1.00, (ii) for the quarter ending June 30, 2006, the ratio of consolidated EBITDA of Cano for the two quarter period multiplied by two to the consolidated Interest Expense of Cano for the two quarter period multiplied by two must be at least 1.75 to 1.00 rather than 2.00 to 1.00, (iii) for the quarter ending September 30, 2006, the ratio of consolidated EBITDA of Cano for the three quarter period multiplied by 4/3 to the consolidated Interest Expense of Cano for the three quarter period multiplied by 4/3 must be at least 2.00 to 1.00 which is the same as it was in the Subordinated Credit Agreement and (iv) for the quarters ending December 31, 2006 and all future quarters, the ratio of consolidated EBITDA of Cano for the four quarter period to the consolidated Interest Expense of Cano for the four quarter period must be at least 2.00 to 1.00 which is the same as it was in the Subordinated Credit Agreement.

Proved Reserves

As set forth in reserve reports based on oil and gas prices at June 30, 2005, except the Corsicana field is as of January 1, 2006, prepared by Forrest A. Garb & Associates, Inc., our independent petroleum engineer, our proved reserves are summarized as follows:

*   In prior SEC filings, we had referred to the Corsicana Field as the Putnam Field.

In the preceding table, the reserve amounts are based on reserve reports as of July 1, 2005, except the Panhandle Field is as of September 1, 2005; the Corsicana Field is as of January 1, 2006; and the New Acquisition is as of April 1, 2006.

Of our 47,178 MBOE of proved reserves, (21%) or 9,797 MBOE are proved producing reserves, 2,062 MBOE (4%) are proved non-producing reserves and 35,319 MBOE (75%) are comprised of proved undeveloped reserves.

Regarding our proved non-producing reserves, approximately eighty-three percent (83%), or 29,400 MBOE, are attributable to a Panhandle Field waterflood implementation. Approximately three percent (3%), or 847 MBOE, are attributable to a surfactant-polymer application in the Corsicana Field and 14%, or 4,946 MBOE, are attributable to waterflood implementation for the new acquisition. The waterflood implementations for the Panhandle Field and new acquisition, and the surfactant-polymer application to the Corsicana Field involve significant capital investment and an extended period of time from the first investment until actual production occurs. Generally, the surfactant-polymer is regarded as more risky as compared to waterflooding; however, the Corsicana Field has been the subject of a successful polymer pilot and we believe conditions for surfactant polymer-flooding are favorable for this field. Our ability to

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recover and successfully convert proved undeveloped reserves to proved producing reserves is greatly contingent upon our ability to obtain additional financing and/or raise additional capital, and further, greatly contingent upon inherent uncertainties associated with drilling and producing oil and gas and volatile oil and gas prices.

Capital Spending Plan for Calendar Year 2006

Our capital spending plan for the remainder of 2006, excluding potential acquisitions, is projected to be $11.3 million to implement developmental projects at our existing fields to increase reserves and production as follows:

Desdemona Field. This field has not been previously waterflooded. We began pilot waterflood operations in May 2005 and expect an initial response by the end of 2006. If the pilot waterfloods are successful, we intend to begin expanding the waterflood to the entire field in 2007. This field also has mineral rights to the Barnett Shale. We are currently evaluating our options with regard to our Barnett Shale rights. The reserve amounts listed in the preceding table do not give any effect to our Barnett Shale rights.

Panhandle Field. These leases were acquired as part of the acquisition of WO Energy. These leases have not been previously waterflooded; however, other leases in the same reservoir have been successfully waterflooded.  We intend to implement a waterflood at certain lease locations and expect to begin the process by the end of 2006.

Nowata Field. This field is currently being waterflooded. We intend to increase production and reserves by applying surfactant-polymer flooding technology. We are continuing to optimize the surfactant-polymer chemistry in the laboratory and intend to begin implementing a surfactant-polymer injection pilot by end of 2006.

Davenport Field. This field is currently being waterflooded. We are evaluating this field for surfactant-polymer flooding technology. Based on this evaluation, we expect to begin a surfactant-polymer pilot toward the mid-2007.

Rich Valley Field. We intend to drill a horizontal lateral in the producing zone to evaluate the feasibility of additional horizontal re-entries and/or infill drilling.

Corsicana Field. Prior to our acquisition of these lease rights, this field had a successful polymer pilot; therefore, conditions for surfactant polymer flooding are very favorable. We intend to conduct laboratory evaluation to determine the optimal mix for a polymer injection in mid-2006 and plan to implement a pilot polymer flood development by the end of 2006.

Operating Activities

For the nine months ended March 31, 2006, we had cash used in our operating activities of $6.3 million as compared to the $0.6 million used in operating activities for the nine months ended March 31, 2005. This is primarily due to the $5.3 million purchase of derivative hedging contracts as discussed in Note 4.

We expect to improve cash flow from operating activities through operational improvements at our existing properties, cash flow generated from the Panhandle Field (i.e. WO Energy) acquisition as discussed in Note 2, the new acquisition as discussed in Note 13 and future acquisitions. The increased cash flow from field operations may be offset, in part, by increased general and administrative costs to support our expanding operations.

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Results of Operations

Overall

For the quarter ended March 31, 2006 (“current quarter”), we had a loss applicable to common stock of $1.1 million, which is $0.3 million higher as compared to the $0.8 million loss applicable to common stock incurred for the quarter ended March 31, 2005 (“prior year quarter”).

For the nine months ended March 31, 2006 (“current nine months”), we had a loss applicable to common stock of $3.1 million, which is $0.5 million higher as compared to the $2.6 million loss applicable to common stock incurred for the nine months ended March 31, 2005 (“prior year nine months”).

The following table summarizes the differences between the quarter and nine months reporting periods.

Results of oil and gas producing operations consist of operating revenues less lease operating expenses, production taxes, accretion of asset retirement obligations, and depletion and depreciation. The $1.9 million increase in the current quarter is attributed to:

•                  Including three months of operating results from the acquisition of the Panhandle Field (i.e. WO Energy) which contributed $1.3 million to net operating income.

•                  Improved operating results from our Davenport, Rich Valley, Desdemona, and Nowata Fields, primarily due to higher oil and gas prices received and increased sales.

The $3.3 million increase in the current nine months is attributable to:

•                  Including four months of operating results from the acquisition of the Panhandle Field (i.e. WO Energy) which contributed $1.8 million to net operating income.

•                  Including two additional months of operating results from the Nowata Field which contributed $0.3 million to net operating income.

•                  Improved operating results from our Davenport, Rich Valley, Desdemona, and Nowata Fields, primarily due to higher oil and gas prices received and increased sales.

The other factors will be addressed in the following discussion.

Operating Revenues

The table below summarizes our operating revenues for the quarter and nine months ended March 31, 2006 and 2005.

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The current quarter operating revenues of $5.4 million represent an improvement of $3.9 million as compared to the prior year quarter of $1.5 million. The $3.9 million improvement is primarily attributable to including three months of operating revenue from the Panhandle Field ($3.2 million of revenue and 59 MBOE of sales); the higher prices received for oil and gas sales; and increased sales from other fields. The average price we received for crude oil sales is generally at or above market prices received at the wellhead. The average price we receive for natural gas sales is approximately the market price received at the wellhead less transportation and marketing expenses.

The current nine months operating revenues of $10.5 million is $6.7 million higher than the prior year nine months of $3.8 million. The $6.7 million improvement is primarily attributable to including four months of operating revenue from the Panhandle Field ($4.3 million of revenue and 80 MBOE of sales); two additional months of Nowata sales ($0.8 million of revenue and 13 MBOE of sales); the higher prices received for oil and gas sales; and increased sales from other fields.

During March 2006, there were grass fires in the Texas Panhandle area. These fires temporarily shut-in production at the Panhandle Field until flow lines were restored. We estimate the temporary shut-in resulted in approximately $0.2 million reduction in revenues for March 2006. By mid-April 2006, the Panhandle Field was producing at 95% of normal operations.

As discussed in Note 13, on April 28, 2006, we acquired additional oil and gas properties in the Panhandle Field located in Texas. These oil and gas properties currently produce approximately 400 net barrels of oil equivalent (“BOE”) per day.

Operating Expenses

For the current quarter, our total operating expenses were $5.1 million, or $2.9 million higher than the prior year quarter of $2.2 million. The $2.9 million increase is primarily attributed to including three months of Panhandle Field operating expenses totaling $1.9 million, higher general & administrative expenses of $1.1 million, and higher other operating expenses of $0.2 million, partially offset by lower deferred compensation expense of $0.3 million.

For the current nine months, our total operating expenses were $11.0 million, or $5.1 million higher than the prior year nine months of $5.9 million. The $5.1 million increase is primarily attributed to including four months of Panhandle Field operating expenses of $2.6 million, the inclusion of an additional two months of Nowata operations ($0.5 million), higher other expenses of $0.3 million, increased general & administrative expenses of $2.6 million, partially offset by lower deferred compensation expense of $0.9 million.

Our LOE consists of costs of producing crude oil and natural gas such as labor, supplies, repairs, maintenance, and utilities. For the current quarter, the LOE per BOE was $21.61 as compared to $26.57 per LOE for the prior year quarter.  For the current nine months, the LOE per BOE was $21.84, which is comparable to $21.57 for the prior year nine months. The current nine months’ amount of $21.84 per BOE is an improvement as compared to the LOE per BOE of $22.88 that we incurred for the twelve month period ended June 30, 2005. We generally incur a high amount of LOE because our fields are more mature

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and typically produce less oil and more water, and they are generally at the end of the primary or secondary production cycle. Since our acquisitions are mature fields, our initial focus is to evaluate the existing operations and make the necessary operational improvements to improve operating efficiency. Based on management’s past experience, it generally requires up to twelve months to fully analyze the acquired field and spend the necessary funds to improve the field operations to meet our operational standards.  We expect these expenditures should lead to increased operational efficiency and reduced operating expenses in future periods.

Our general and administrative (G&A) expenses consist of support services for our operating activities and investor relations costs. For the current quarter, our G&A expenses totaled $1.8 million, which is $1.1 million higher than the prior year quarter. The primary contributor to the $1.1 million increase was increased labor and staffing costs of $0.6 million. The remaining increase of $0.5 million is due to higher legal fees to comply with regulatory requirements, higher travel costs and increased insurance costs. For the current nine months, our G&A expenses totaled $4.7 million, which is $2.6 million higher than the prior year nine months of $2.1 million. Of the $2.6 million increase, $1.3 million is attributed increased labor and staffing costs, and the same factors previously mentioned, plus expenses associated with the Sabine joint venture, as discussed in Note 10.

On January 6, 2006, our Board of Directors approved the following non-executive director compensation schedule. Each director shall receive an annual cash retainer of $25,000. Each director shall be paid $1,000 cash for each Board meeting and Board committee meeting attended. The Audit Committee Chairman shall receive an additional annual cash retainer of $5,000. The Compensation Committee Chairman, the Corporate Governance Committee Chairman, the Nominating Committee Chairman and the chairman of any other committee or special committee established by the Board shall be paid an additional annual cash retainer of $3,000.

During January 2006, our executive officers were awarded annual salary increases totaling approximately $370,000.

Loss on Hedging Contracts

As discussed in Note 4 to the financial statements, during December 2005, we paid $5.3 million to enter into financial contracts to set price floors for crude oil and natural gas. In accordance with SFAS 133, we recorded a Loss on Hedging Contracts of $2.9 million, of which $1.3 million occurred during the current quarter, to reflect the fair value of the derivative instruments as of March 31, 2006. By their nature, these derivative instruments can be highly volatile to our earnings. A five percent change in these prices for our derivative instruments can impact earnings by approximately $184,000. We did not have hedging contracts during the nine months ended March 31, 2005.

Also, during the current quarter, as discussed in Note 4, there were settlements under our derivative agreements due to Cano amounting to $140,996. The settlements were cumulative monthly payments due to Cano since the NYMEX gas price was lower than the $8.50 “floor gas price.”

Interest Expense

The interest expense we incurred in the current quarter and current nine months ended March 31, 2006 of $0.9 million and $1.3 million, respectively, resulted directly from senior and subordinated credit agreements we entered into on November 29, 2005, as discussed in Note 3 to the financial statements. We did not have credit agreements during the nine month period ended March 31, 2005.

Deferred Income Tax Benefit

As the result of the recognition of the deferred tax liabilities assumed in the acquisitions of WO Energy and Square One, as discussed in Notes 2 and 11, respectively, to the financial statements, we now have a net deferred tax liability. This allows us to recognize deferred tax benefits from generation of net operating losses because a valuation allowance against such items is not required. We review our deferred tax assets

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at least quarterly and record a valuation allowance against those assets when we conclude that it is more likely than not that those assets will expire without being utilized. For the quarter and nine months ended March 31, 2006, we recorded a deferred income tax benefit of $677,000 and $1,470,000, respectively.

Preferred Stock Discount

The reduced preferred stock discount amounting to $0.4 million occurred during the nine months ended March 31, 2005 and was attributable to certain issuances of preferred stock during that period. Since we did not issue preferred stock during the nine months ended March 31, 2006, there is no preferred stock discount for the current nine month period.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3. Controls and Procedures.

As of the end of the period covered by this report, we conducted an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is: (1) accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure; and (2) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. There was no change in our internal control over financial reporting or in other factors that could affect the internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

Litigation

On March 23, 2006, the following lawsuit was filed in the 100^th 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, Ltd, and W.O. Energy, Inc. The plaintiffs claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs (i) allege negligence and gross negligence and (ii) seek undisclosed 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. In addition, the plaintiffs seek (i) termination of certain oil and gas leases, (ii) reimbursement for their attorney’s fees and (iii) exemplary damages.

Due to the inherent risks of litigation and the fact that this case is in the early stages of discovery, the outcome of this case is uncertain and unpredictable; however, at this time Cano management believes the suit is without merit and is vigorously defending itself and its subsidiaries.

On April 28, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of

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Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. There are 43 plaintiffs that claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs (i) allege negligence, gross negligence, trespass and nuisance and (ii) seek undisclosed damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses. In addition, the plaintiffs seek (i) reimbursement for their attorney’s fees and (ii) exemplary damages.

Due to the inherent risks of litigation and the fact that this case is in the early stages of discovery, the outcome of this case is uncertain and unpredictable; however, at this time Cano management believes the suit is without merit and is vigorously defending itself and its subsidiaries.

On April 10, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. On May 1, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1923, Chisum Family Partnership, Ltd. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. Although Cano is aware that these two lawsuits were filed, neither it nor any of its subsidiaries that are named in the lawsuits have been served with process. The plaintiffs in both cases claim that the electrical wiring and equipment of Cano Petroleum, Inc. or certain of its subsidiaries relating to its oil and gas operations started a wildfire that began on March 12, 2006 in Carson County.

The plaintiffs in both cases (i) allege negligence and trespass and (ii) seek undisclosed damages, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs in both cases seek (i) reimbursement for their attorney’s fees and (ii) exemplary damages.

Due to the inherent risks of litigation and the fact that neither Cano nor its subsidiaries have been served with these suits, the outcome of these case is uncertain and unpredictable; however, at this time Cano management believes the suits are without merit and, if and when it is served, will vigorously defend itself and its subsidiaries.

Other

Occasionally, we are involved in various 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, including due to the existence of insurance coverage, indemnification and escrow accounts, will have a material effect on our financial position or results of operations. None of our directors, officers or affiliates, owners of record or beneficially of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to our business or has a material interest adverse to our business.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

There were no unregistered sales of equity securities during the third quarter ended March 31, 2006.

Item 3. Defaults Upon Senior Securities.

There has been no material default in the payment of principal, interest, a sinking or purchase fund installment, or any other material default not cured within 30 days, with respect to any indebtedness exceeding five percent of our total assets. There also has been no material arrearage in the payment of dividends or any other material delinquency not cured within 30 days, with respect to any class of preferred stock which is registered or which ranks prior to any class of our registered securities, or with respect to any class of preferred stock of any significant subsidiary.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

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Item 5. Other Information.

None.

Item 6. Exhibits.

*                 Filed herewith

+                 Management contract or compensatory plan, contract or arrangement

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SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.