Cano Petroleum 10Q 2010 Q1 Quarterly report

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 September 30, 2009

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

Commission file number 001-32496

CANO PETROLEUM, INC.

(Exact name of Registrant as specified in its charter)

Delaware		77-0635673
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification Number)

801 Cherry St., Suite 3200 Fort Worth, Texas (Address of principal executive office)		76102 (Zip Code)

(817) 698-0900
(Registrant’s telephone number, including area code)

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

Title of each class:		Name of each exchange on which registered:
COMMON STOCK, PAR VALUE $.0001 PER SHARE		NYSE AMEX

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

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.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company x

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 November 12, 2009 was 45,570,147 shares.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

CANO PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			June 30,
In Thousands, Except Shares and Per Share Amounts	2009			2009
*ASSETS*
Current assets
Cash and cash equivalents	$	761		$	392
Accounts receivable	2,474			2,999
Derivative assets	4,385			4,955
Inventory and other current assets	1,394			810
Total current assets	9,014			9,156
Oil and gas properties, successful efforts method	294,677			288,857
Less accumulated depletion and depreciation	(41,358		)	(40,208		)
Net oil and gas properties	253,319			248,649
Fixed assets and other, net	3,071			3,240
Derivative assets	1,840			2,882
Goodwill	101			101
TOTAL ASSETS	$	267,345		$	264,028

*LIABILITIES, TEMPORARY EQUITY AND STOCKHOLDERS’ EQUITY*
Current liabilities
Accounts payable	$	5,837		$	4,434
Accrued liabilities	2,653			2,003
Deferred tax liabilities	1,432			1,431
Oil and gas sales payable	718			702
Derivative liabilities	199			159
Current portion of asset retirement obligations	88			86
Total current liabilities	10,927			8,815
Long-term liabilities
Long-term debt	61,200			55,700
Asset retirement obligations	2,883			2,818
Derivative liabilities	644			—
Deferred tax liabilities	21,200			22,831
Total liabilities	96,854			90,164
Temporary equity
Series D convertible preferred stock and cumulative paid-in-kind dividends; par value $.0001 per share, stated value $1,000 per share; 49,116 shares authorized; 23,849 issued at September 30, 2009 and June 30, 2009, respectively; liquidation preference at September 30, 2009 and June 30, 2009 of $27,265 and $26,987, respectively	25,683			25,405
Commitments and contingencies (Note 12)
Stockholders’ equity
Common stock, par value $.0001 per share; 100,000,000 authorized; 47,273,224 and 45,570,147 shares issued and outstanding, respectively, at September 30, 2009; and 47,297,910 and 45,594,833 shares issued and outstanding, respectively, at June 30, 2009	5			5
Additional paid-in capital	189,906			189,526
Accumulated deficit	(44,406		)	(40,375		)
Treasury stock, at cost; 1,703,077 shares held in escrow at September 30, 2009 and June 30, 2009, respectively	(697		)	(697		)
Total stockholders’ equity	144,808			148,459
TOTAL LIABILITIES, TEMPORARY EQUITY AND STOCKHOLDERS’ EQUITY	$	267,345		$	264,028

See accompanying notes to these unaudited financial statements.

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	September 30,
In Thousands, Except Per Share Data	2009			2008
Operating Revenues:
Crude oil sales	$	4,431		$	8,118
Natural gas sales	833			2,734
Other revenue	—			79
Total operating revenues	5,264			10,931

Operating Expenses:
Lease operating	4,416			5,071
Production and ad valorem taxes	467			1,052
General and administrative	3,573			4,860
Depletion and depreciation	1,263			1,211
Accretion of discount on asset retirement obligations	67			75
Total operating expenses	9,786			12,269

Loss from operations	(4,522		)	(1,338		)

Other income (expense):
Interest expense and other	(158		)	(132		)
Gain (loss) on derivatives	(512		)	23,695
Total other income (expense)	(670		)	23,563

Income (loss) from continuing operations before income taxes	(5,192		)	22,225
Deferred income tax benefit (expense)	1,631			(8,619		)

Income (loss) from continuing operations	(3,561		)	13,606
Loss from discontinued operations, net of related taxes of $491 in 2008 (Note 6)	—			(852		)
Net income (loss)	(3,561		)	12,754

Preferred stock dividend	(470		)	(936		)

Net income (loss) applicable to common stock	$	(4,031	)	$	11,818

Net income (loss) per share - basic
Continuing operations	$	(0.09	)	$	0.28
Discontinued operations	—			(0.02		)
Net income (loss) per share - basic	$	(0.09	)	$	0.26

Net income (loss) per share - diluted
Continuing operations	$	(0.09	)	$	0.25
Discontinued operations	—			(0.02		)
Net income (loss) per share - diluted	$	(0.09	)	$	0.23

Weighted average common shares outstanding
Basic	45,571			46,230
Diluted	45,571			54,739

See accompanying notes to these unaudited financial statements.

CANO PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
JULY 1, 2009 THROUGH SEPTEMBER 30, 2009
(Unaudited)

					Additional										Total
	Common Stock				Paid-in			Accumulated			Treasury Stock				Stockholders’
Dollar Amounts in Thousands	Shares		Amount		Capital			Deficit			Shares	Amount			Equity

Balance at July 1, 2009	47,297,910		$	5	$	189,526		$	(40,375	)	1,703,077	$	(697	)	$	148,459

Forfeiture and surrender of restricted stock	(24,686	)	—		(28		)	—			—	—			(28		)

Stock-based compensation expense	—		—		408			—			—	—			408

Preferred stock dividend	—		—		—			(470		)	—	—			(470		)

Net loss	—		—		—			(3,561		)	—	—			(3,561		)

Balance at September 30, 2009	47,273,224		$	5	$	189,906		$	(44,406	)	1,703,077	$	(697	)	$	144,808

See accompanying notes to these unaudited financial statements.

CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended September 30,
In Thousands	2009			2008
Cash flow from operating activities:
Net income (loss)	$	(3,562	)	$	12,754
Adjustments needed to reconcile net income (loss) to net cash provided by operations:
Unrealized loss (gain) on derivatives	2,307			(24,247		)
Accretion of discount on asset retirement obligations	68			77
Depletion and depreciation	1,262			1,219
Impairment of oil and gas properties	—			3,516
Stock-based compensation expense	408			958
Deferred income tax expense (benefit)	(1,631		)	8,128
Amortization of debt issuance costs and prepaid expenses	402			362

Changes in assets and liabilities relating to operations:
Accounts receivable	1,063			562
Derivative assets	(549		)	—
Inventory and other current assets and liabilities	(894		)	(956		)
Accounts payable	994			(107		)
Accrued liabilities	621			483
Oil and gas sales payable	16			(234		)
Derivative liability	—			144
Net cash provided by operations	505			2,659

Cash flow from investing activities:
Additions to oil and gas properties, fixed assets and other	(5,445		)	(16,510		)
Proceeds from sale of equipment used in oil and gas activities	—			2,135
Net cash used in investing activities	(5,445		)	(14,375		)

Cash flow from financing activities:
Repayments of long-term debt	—			(54,500		)
Borrowings of long-term debt	5,500			23,700
Payments for debt issuance costs	—			(305		)
Proceeds from issuance of common stock, net	—			53,908
Payment of preferred stock dividend	(191		)	(403		)
Net cash provided by financing activities	5,309			22,400

Net increase in cash and cash equivalents	369			10,684
Cash and cash equivalents at beginning of period	392			771
Cash and cash equivalents at end of period	$	761		$	11,455

Supplemental disclosure of noncash transactions:
Payments of preferred stock dividend in kind	$	278		$	533

Supplemental disclosure of cash transactions:
Cash paid during the period for interest	$	666		$	605

See accompanying notes to these unaudited financial statements.

CANO PETROLEUM, INC.

NOTES TO FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND USE OF ESTIMATES

Consolidation and Use of Estimates

The 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. 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 acquisitions, 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, 2009.

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Cano and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. 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 valuation of our commodity derivatives includes the observability of quoted market prices and an assessment of potential non-performance of the counterparties. It is at least reasonably 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 may affect the amount 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 catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment. Our proved reserves estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserves estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.

New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued a standard that established the FASB Accounting Standards CodificationTM (“ASC”) and amended the hierarchy of GAAP such that the ASC became the single source of authoritative nongovernmental GAAP. The ASC did not change current GAAP, but was intended to simplify user access to all authoritative GAAP by providing all the authoritative literature related to a particular topic in one place. All previously existing accounting standard documents were superseded and all other accounting literature not included in the ASC is considered non-authoritative. New accounting standards issued subsequent to June 30, 2009 are communicated by the FASB through Accounting Standards Updates (ASUs). The ASC became effective for us on July 1, 2009. This standard did not have an impact on our financial position, results of operations or cash flows. Throughout the notes to the consolidated financial statements, references that were previously made to various former authoritative GAAP pronouncements have been conformed to the appropriate section of the ASC.

In December 2007, the FASB issued ASC 805 (formerly Statement of Financial Accounting Standards (“SFAS”) No. 141 (revised 2007), Business Combinations). Among other things, ASC 805 establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. ASC 805 is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted ASC 805 on July 1, 2009. This standard will change our accounting treatment for prospective business combinations.

In December 2007, the FASB issued ACS 810 (formerly SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51). ASC 810 establishes accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted ASC 810 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In March 2008, the FASB issued ASC 815 (formerly SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement 133). ASC 815 expands the required disclosures to discuss the uses of derivative instruments; the accounting for derivative instruments and related hedged items under ASC 815, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In June 2008, the FASB issued ASC 260 (formerly EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities). ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of earnings per share under the two-class method. Under ASC 260, share-based payment awards that contain nonforfeitable rights to dividends are “participating securities”, and therefore should be included in computing earnings per share using the two-class method. ASC 260 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 260 on July 1, 2009. The effect of adopting ASC 260 increased the number of shares used to compute earnings per share; however, the adoption of ASC 260 did not have a material impact on our financial position, results of operations or cash flows.

In December 2008, the FASB issued ASC 815 (formerly EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock). ASC 815 affects companies that have provisions in their securities purchase agreements (for warrants and convertible instruments) that reset conversion prices based upon new issuances by companies at prices below the current conversion price of said instrument. Warrants and convertible instruments with such provisions will require the embedded derivative instrument to be bifurcated and separately accounted for as a derivative. Subject to certain exceptions, our preferred stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. ASC 815 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows as the reset conversion provision did not meet the definition of a derivative since it was not readily net-cash settled.

In June 2009, the FASB issued ASC 855 (formerly SFAS 165, Subsequent Events) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date, but prior to the issuance of financial statements. Specifically, ASC 855 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855 is effective for

financial statements issued for interim or annual periods ending after June 15, 2009. We adopted ASC 855 on June 30, 2009 and considered subsequent events through November 13, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

2. PENDING MERGER WITH RESACA

On September 29, 2009, the boards of directors of Cano and Resaca Exploitation, Inc. approved an Agreement and Plan of Merger (the “Merger Agreement”) by and among Cano, Resaca and Resaca Acquisition Sub, Inc., a Delaware corporation and wholly-owned subsidiary of Resaca (“Merger Sub”), pursuant to which Merger Sub will be merged with and into Cano (the “Merger”) and Cano will become a wholly-owned subsidiary of Resaca.

Under the terms of the proposed Merger, each share of Cano common stock will be converted into the right to receive 2.10 shares of common stock of Resaca (or 0.42 shares of Resaca common stock if the proposed 1 to 5 reverse stock split is approved by the Resaca shareholders prior to the Merger) and each share of Cano Series D Convertible Preferred Stock (the “Preferred Stock”) will be converted into the right to receive one share of Resaca Series A Convertible Preferred Stock. The Merger is intended to be a tax-free transaction to the Resaca shareholders and to the Cano stockholders to the extent the Cano common stockholders receive Resaca common stock and the Cano preferred stockholders receive Resaca preferred stock in the Merger.

Consummation of the transactions contemplated by the Merger Agreement is conditioned upon, among other things, (1) approval of the holders of the common stock and preferred stock of Cano, (2) approval of the holders of the common stock of Resaca, (3) the listing of Resaca common stock on the NYSE Amex, (4) the refinancing of existing bank debt of Resaca and Cano, (5) the receipt of required regulatory approvals, (6) Resaca’s application for readmission to the Alternative Investment Market of the London Stock Exchange and (7) the effectiveness of a registration statement relating to the shares of Resaca common stock to be issued in the Merger. The Merger Agreement contains certain termination rights for each of Cano and Resaca, including the right to terminate the Merger Agreement to enter into a Superior Proposal (as such term is defined in the Merger Agreement). In the event of a termination of the Merger Agreement under certain specified circumstances described in the Merger Agreement, one party will be required to pay the other party a termination fee of $3,500,000.

We entered into stock voting agreements with 75% of the holders of Cano’s Preferred Stock on various dates between September and November 2009. Each stock voting agreement contains the same terms and provides, among other things, that each of the preferred holders will vote all its shares of our stock (a) in favor of an amendment to the Certificate of Designations, Preferences and Rights of Series D Convertible Preferred Stock of Cano (the “Series D Amendment”), (b) in favor of adoption of the Merger Agreement, and (c) in accordance with the recommendation of our Board of Directors in connection with any Target Acquisition Proposal (as such term is defined in the Merger Agreement). The Series D Amendment generally provides that the holders of Preferred Stock shall have no rights arising from the proposed Merger with Resaca (including any right to require us to redeem their shares of Preferred Stock) other than the right to receive the merger consideration specified in the Merger Agreement. To be effective, the Series D Amendment must be approved by the holders of a majority of the shares of Preferred Stock, voting as a separate class, and by the holders of a majority of the shares of our common stock, voting as a separate class, and then filed by us with the Secretary of State of Delaware.

On October 20, 2009, we entered into a Stock Voting Agreement with S. Jeffrey Johnson, our Chief Executive Officer and Chairman of our board of directors, which provides, among other things, that Mr. Johnson will vote all of his shares of our stock in favor of the Series D Amendment. Mr. Johnson owns approximately 3.7% of the Preferred Stock. During the quarter ended September 30, 2009, we paid Mr. Johnson a cash preferred dividend payment of approximately $20,000.

Forward-looking statements in this Quarterly Report on Form 10-Q reflect Cano’s current plans as a stand-alone entity and do not take into account the impact of the proposed Merger with Resaca, except where such statements specifically relate to the proposed Merger.

Resaca is an independent oil and gas exploitation company headquartered in Houston, Texas, with operations focused on properties in the United States, specifically in the Permian Basin of West Texas and southeast New Mexico.

3. LIQUIDITY

At September 30, 2009, we had cash and cash equivalents of $0.8 million and negative working capital of $1.9 million. For the three-month period ended September 30, 2009, we generated cash flow from operations of $0.5 million.

We depend on our credit agreements, as described in Note 4, to fund a portion of our operating and capital needs. Under our amended and restated credit agreement (the “ARCA”), the initial and current borrowing base, based upon our proved reserves, is $60.0 million. At September 30, 2009, our remaining available borrowing capacity under the ARCA was $13.8 million. At November 13, 2009, our remaining available borrowing capacity was $10.0 million. Pursuant to the terms of the ARCA, our borrowing base is to be redetermined based upon our June 30, 2009 reserve report. We have submitted our reserve report and other financial information to our lenders. We have not received formal notification of any changes to our borrowing base.

At September 30, 2009, we were in compliance with the debt covenants contained in each of our credit agreements. The compliance determination for the twelve-month period ending December 31, 2009 will be the first financial covenant tests which will exclude the gain from our sale of the Pantwist Properties (see Note 6). Based upon our nine month operating results through September 30, 2009, it appears likely that we may fall out of compliance with one or more of our financial covenants under our credit agreements as of December 31, 2009. If a combination of increased production, rising commodity prices, changes in our capital structure, the closing of our pending Merger and other actions do not occur by December 31, 2009, we anticipate not being in compliance with the covenants. In that event, we will seek covenant relief from our lenders, though there can be no assurance that we will be successful in obtaining such relief.

Our credit agreements, discussed in Note 4, include change of control provisions which require us to refinance the credit agreements at the close of the Merger. We are working with Resaca regarding the credit arrangements for the combined company.

4. LONG-TERM DEBT

At September 30, 2009 and June 30, 2009, the aggregate outstanding amounts under our credit agreements were $61.2 million and $55.7 million, respectively. The $61.2 million consisted of outstanding borrowings under the ARCA and the subordinated credit agreement of $46.2 million and $15.0 million, respectively. At September 30, 2009, the average interest rates under the ARCA and subordinated credit agreements were 2.69% and 6.30%, respectively.

Our long-term debt consists of the ARCA (current borrowing base of $60.0 million) and our subordinated credit agreement (borrowing availability of $15.0 million). As discussed under Note 3, the $60.0 million borrowing base under the ARCA is to be redetermined based on our June 30, 2009 reserve report. Our lenders are Union Bank of North America, N.A. (“UBNA”), acting as administrative agent, and Natixis.

5. COMMODITY DERIVATIVES

Our derivatives consist of commodity derivatives and an interest rate swap arrangement.

Commodity Derivatives

Pursuant to our ARCA and subordinated credit agreements, discussed in Note 4, we are required to maintain our “collar” commodity derivative contracts. We have commodity derivatives to partially mitigate the risk associated with extreme fluctuations of prices for 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 September 30, 2009, we maintained the following “collar” commodity derivative contracts with UBNA as our counterparty, which is one of the senior lenders under the ARCA:

Time Period	Floor Oil Price		Ceiling Oil Price		Barrels Per Day	Floor Gas Price		Ceiling Gas Price		Mcf per Day	Barrels of Equivalent Oil per Day(a)
10/1/09 - 12/31/09	$	80.00	$	110.90	367	$	7.75	$	10.60	1,667	644
10/1/09 - 12/31/09	$	85.00	$	104.40	233	$	8.00	$	10.15	1,133	422
1/1/10 - 12/31/10	$	80.00	$	108.20	333	$	7.75	$	9.85	1,567	594
1/1/10 - 12/31/10	$	85.00	$	101.50	233	$	8.00	$	9.40	1,033	406
1/1/11 - 3/31/11	$	80.00	$	107.30	333	$	7.75	$	11.60	1,467	578
1/1/11 - 3/31/11	$	85.00	$	100.50	200	$	8.00	$	11.05	967	361

(a) This column is computed by dividing the “Mcf per Day” by 6 and adding “Barrels per Day.”

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

Time Period	Fixed Oil Price		Barrels Per Day
4/1/11 - 12/31/11	$	75.90	700
1/1/12 - 12/31/12	$	77.25	700

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 have the interest rate swap agreement to partially mitigate the risk associated with interest rate fluctuations on our interest expense. 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 quarters ended September 30, 2009 and 2008, respectively, the gain (loss) on derivatives reported in our consolidated statements of operations is summarized as follows:

	Location of Gain	Three Months Ended September 30,
	(Loss) On Derivatives	2009			2008
Settlements received/accrued on commodity derivatives	Other income (expense)	$	1,851		$	—
Settlements paid/accrued on commodity derivatives	Other income (expense)	—			(552		)
Settlements paid/accrued on interest rate swap	Other income (expense)	(56		)	—
Realized gain (loss) on derivatives	Other income (expense)	1,795			(552		)
Unrealized gain (loss) on commodity derivatives	Other income (expense)	(2,204		)	24,247
Unrealized loss on interest rate swap	Other income (expense)	(103		)	—
Gain (loss) on derivatives	Other income (expense)	$	(512	)	$	23,695

The realized gain (loss) on derivatives consists of actual cash settlements under our commodity collars and interest rate swap derivatives during the respective periods. 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 us under the interest rate swap related to 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 liabilities. At both September 30, 2009 and June 30, 2009, we had recorded a $0.6 million receivable from our counterparty included in accounts receivable on our consolidated balance sheet at both dates.

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 valuation to our counterparties’ independently derived valuation to further validate our mark-to-market valuation. During the three-month period ended September 30, 2009, we recognized an unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $2.2 million. During the three-month period ended September 30, 2008, we recognized an unrealized gain on commodity derivatives in our consolidated statements of operations amounting to $24.2 million.

The unrealized loss on interest rate swap represents estimated future settlements under our aforementioned 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. During the three-month period ended September 30, 2009, we recognized realized and unrealized losses on interest rate swaps in our consolidated statements of operations amounting to $0.1 million each. Since we did not implement the interest rate swap until January 2009, we did not have realized/unrealized gain or loss on the interest rate swap during the three-month period ended September 30, 2008.

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 insignificant to the fair value of the 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.

Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

The estimated fair value of derivatives included in the consolidated balance sheet at September 30, 2009 is summarized below.

In thousands
Derivative assets (Level 2):
Crude oil collars and price floors — current	$	2,560
Crude oil collars and price floors — noncurrent	1,097
Natural gas collars and price floors — current	1,825
Natural gas collars and price floors — noncurrent	595
Interest rate swap — noncurrent	148
Derivative liability (Level 2)
Interest rate swap — current	(199		)
Crude oil swap - noncurrent	(644		)
Net derivative assets (Level 2)	$	5,382
Asset retirement obligation (Level 3)	$	(2,971	)

The following table shows the reconciliation of changes in the fair value of the net derivative assets and asset retirement obligation classified as Level 2 and 3, respectively, in the fair value hierarchy for the three-month period ended September 30, 2009.

	Total Net			Asset
	Derivative			Retirement
In thousands	Assets			Obligation
Balance at June 30, 2009	$	7,678		$	2,904
Unrealized loss on derivatives	(2,307		)	—
Settlements, net	11			—
Accretion of discount	—			67
Balance at September 30, 2009	$	5,382		$	2,971

The change from net derivative assets of $7.7 million at June 30, 2009 to net derivative assets of $5.4 million at September 30, 2009 is attributable to the increases in crude oil and natural gas futures prices. These amounts are based on our mark-to-market valuation of these derivatives at September 30, 2009 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 (in thousands):

	Asset Derivatives						Liability Derivatives
	September 30, 2009			June 30, 2009			September 30, 2009				June 30, 2009
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair			Balance Sheet	Fair
	Location	Value		Location	Value		Location	Value			Location	Value
Derivatives not designated as hedging instruments
Commodity derivative contracts	Derivatives - current	$	4,385	Derivatives - current	$	4,955	Derivatives - current	$	—		Derivatives - current	$	—
Commodity derivative contracts	Derivatives - noncurrent	1,692		Derivatives - noncurrent	2,670		Derivatives - noncurrent	(644		)	Derivatives - noncurrent	—
Interest rate swaps	Derivatives - noncurrent	148		Derivatives - noncurrent	212		Derivatives - current	(199		)	Derivatives - current	(159		)

Total derivatives not designated as hedging instruments		$	6,225		$	7,837		$	(843	)		$	(159	)

Total derivatives designated as hedging instruments		$	—		$	—		$	—			$	—

Total derivatives		$	6,225		$	7,837		$	(843	)		$	(159	)

6. DISCONTINUED OPERATIONS

On October 1, 2008, we completed the sale of our wholly-owned subsidiary, Pantwist, LLC, for a net purchase price of $40.0 million consisting of a $42.7 million purchase price adjusted for $2.1 million of net cash received from discontinued operations during the three months ended September 30, 2008 and $0.6 million of advisory fees. The sale had an effective date of July 1, 2008.

On December 2, 2008, we sold our interests in our Corsicana oil and gas properties (the “Corsicana Properties”) for $0.3 million. In the quarter ended September 30, 2008, we recorded a $3.5 million ($2.3 million after-tax) impairment of the Corsicana Properties, as we determined that we would not be developing its proved undeveloped reserves within the next five years.

The operating results of Pantwist, LLC and the Corsicana Properties for the three months ended September 30, 2008 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below.

Operating Revenues:
Crude oil sales	$	1,311
Natural gas sales	1,696
Total operating revenues	3,007
Operating Expenses:
Lease operating	601
Production and ad valorem taxes	197
Impairment of long-lived assets	3,516
Depletion and depreciation	8
Accretion of discount on asset retirement obligations	2
Interest expense, net	26
Total operating expenses	4,350
Income before income taxes	(1,343		)
Income tax provision	491
Income from discontinued operations	$	(852	)

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

7. DEFERRED COMPENSATION

As of September 30, 2009, we had non-vested restricted shares totaling 386,667 shares to key employees pursuant to our 2005 Long-Term Incentive Plan, as summarized below:

	Shares		Weighted Average Grant-date Fair Value		Fair Value $000s
Non-vested restricted shares at June 30, 2009	480,000		$	6.97	$	3,344
Shares vested	(68,647	)	$	5.84	$	(401	)
Shares forfeited	(24,686	)	$	5.84	(144		)
Non-vested restricted shares at September 30, 2009	386,667		$	7.24	$	2,799

The restricted share grants will vest to the employees based on future years of service ranging from one to three years depending on the life of the award agreement. Pursuant to the Merger discussed in Note 2, the non-vested restricted shares would vest upon the completion of the Merger. The fair value of the grants is based on our actual stock price on the date of grant multiplied by the number of restricted shares granted. As of September 30, 2009, the value of non-vested restricted shares amounted to $2.8 million. For the quarters ended September 30, 2009 and 2008, we have expensed $0.3 million and $0.8 million, respectively, to stock 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 restricted shares.

8. STOCK OPTIONS

During the three-month period ended September 30, 2009, we did not grant additional stock options. A summary of outstanding options as of September 30, 2009 is as follows:

	Shares		Weighted Average Exercise Price
Outstanding at June 30, 2009	1,400,002		$	4.42
Options forfeited	(15,541	)	$	4.87
Outstanding at September 30, 2009	1,384,461		$	4.41

Based on our $1.27 stock price at September 30, 2009, the intrinsic value of both the options outstanding and exercisable was approximately $0.2 million.

Total options exercisable at September 30, 2009 amounted to 1,008,705 shares and had a weighted average exercise price of $4.41. 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 each of the quarters ended September 30, 2009 and 2008, we recorded charges to stock compensation expense of $0.1 million and $0.2 million, respectively, for the estimated fair value of the options granted to our directors and employees. As of September 30, 2009, total compensation cost related to non-vested option awards not yet recognized was $0.4 million. We expect to recognize the remaining unrecognized amount over the related requisite service periods of one to three years. Pursuant to the Merger, discussed in Note 2, the outstanding stock options would vest upon completion of the Merger.

9. NET INCOME (LOSS) PER COMMON SHARE

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common shareholders by the weighted average number of shares of common stock outstanding. Diluted net income (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 summarized below were not included in dilutive weighted average shares outstanding for the three-month period ended September 30, 2009 as their effects would have been anti-dilutive.

Stock options		1,384,461
Preferred stock		4,147,652
PIK dividends		594,167

The following table reconciles earnings and shares used in the computation of basic and diluted earnings per share for the three months ended September 30, 2008:

In thousands, except per share data	Earnings		Shares	Earnings per Share
Basic	$	11,818	46,230	$	0.26

Effect of dilutive securities:
Conversion of preferred stock and PIK dividends	936		8,502
Stock options			7
Diluted	$	12,754	54,739	$	0.23

10. INCOME TAXES

The effective income tax rate for the quarter ended September 30, 2009 was 31% as compared to 107% for our year ended June 30, 2009. The income tax rate was higher for our year-end June 30, 2009 because of an increase in the state tax rate and other permanent items.

11. 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 claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and natural gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas.

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

The Final Judgment was appealed and a decision was reached on March 11, 2009, as the Court of Appeals for the Tenth District of Texas in Amarillo affirmed in part and reversed in part the ruling of the 100th Judicial District Court. The Court of Appeals (a) affirmed the trial court’s granting of summary judgment in Cano’s favor for breach of contract/termination of an oil and gas lease and (b) reversed the trial court’s granting of summary judgment in Cano’s favor on plaintiffs’ claims of Cano’s negligence. The Court of Appeals ordered the case remanded to the 100th Judicial District Court. On March 30, 2009, the plaintiffs filed a motion for rehearing with the Court of

Appeals and requested a rehearing on the trial court’s ruling in favor of the defendants on the plaintiffs’ breach of contract/termination of an oil and gas lease claim. On June 30, 2009, the Court of Appeals ruled to deny the plaintiff’s motion for rehearing. On August 17, 2009 we filed an appeal with the Texas Supreme Court to request the reversal of the Court of Appeals ruling regarding our potential negligence.

Due to the inherent risk of litigation, the ultimate outcome of this case is uncertain and unpredictable. At this time, Cano management continues to believe that this lawsuit is without merit and will continue to vigorously defend itself and its subsidiaries, while seeking cost-effective solutions to resolve this lawsuit. Based on our knowledge and judgment of the facts as of November 13, 2009, we believe our financial statements present fairly the effect of actual and anticipated ultimate costs to resolve these matters as of September 30, 2009.

Securities Litigation

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 (4:09-CV-308-A).

On July 2, 2009, the plaintiffs filed an amended complaint that added as defendants Cano, Cano’s Chief Executive Officer and Chairman of the Board, Jeff Johnson, Cano’s former Senior Vice President and Chief Financial Officer, Morris B. “Sam” Smith, Cano’s current Senior Vice President and Chief Financial Officer, Ben Daitch, Cano’s Vice President and Principal Accounting Officer, Michael Ricketts and Cano’s Senior Vice President of Engineering and Operations, Patrick McKinney, and dismissed Gerald W. Haddock, a former director of Cano, as a defendant. The amended complaint alleges that the prospectus for the Secondary Offering contained statements regarding Cano’s proved reserve amounts and standards that were materially false and overstated Cano’s proved reserves. The plaintiff is seeking to certify the lawsuit as a class action lawsuit and is seeking an unspecified amount of damages. On July 27, 2009, the defendants moved to dismiss the lawsuit. Due to the inherent risk of litigation, the outcome of this lawsuit is uncertain and unpredictable; however, Cano, its officers and its outside directors intend to vigorously defend the lawsuit. Cano is cooperating with its Directors and Officers Liability insurance carrier regarding the defense of the lawsuit.

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 on Financial Condition and Results of Operations

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 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, 2010 as a stand-alone entity and do not take into account the impact of the proposed merger (the “Merger”) with Resaca Exploitation, Inc. (“Resaca”), except where such statements specifically relate to the proposed Merger.

You should read the following discussion and analysis in conjunction with the consolidated financial statements of Cano 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.

Overview

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

In September 2009, we entered into a merger agreement with Resaca (the “Merger Agreement”) pursuant to which Cano will be acquired by Resaca through the merger of a wholly-owned subsidiary of Resaca with and into Cano. The Merger is subject to customary conditions, including the approval of the common and preferred stockholders of Cano and the common shareholders of Resaca. The companies will hold separate meetings of their shareholders to approve the Merger. Assuming shareholder approval is received, the Merger is expected to be completed within a few days following the shareholder meetings. For more information regarding the proposed Merger, please refer to the Note 2 of the accompanying Consolidated Financial Statements and the joint proxy statement/prospectus of Resaca and Cano that is included in the registration statement on Form S-4 (File No. 333-162652) filed by Resaca with the SEC, and other relevant materials that may be filed by Cano or Resaca with the SEC. The following discussion relates to our plans without regard to the potential impact of the proposed Merger.

We are focused on enhancing the infrastructure and waterflood operations in our two largest properties, Cato and Panhandle. These development activities are more clearly described below under “Development Capital Expenditures and Operating Activities Update.” We believe our portfolio of crude oil and natural gas properties provides opportunities to apply our operational strategy.

Our June 30, 2009 proved reserves of 49.1 MMBOE, were comprised 7.7 MMBOE of PDP, 2.4 MMBOE of PDNP, and 39.0 MMBOE of PUD. Crude oil reserves accounted for 79% of our total reserves at June 30, 2009.

Development Capital Expenditures and Operating Activities Update

For the year ending June 30, 2010 (the “2010 Fiscal Year”), our Board of Directors approved a development capital expenditures budget of $13.9 million (which excludes capitalized general and administrative and interest expenses). Our development capital budget is designed to minimize drawing on our available borrowing capacity under the ARCA until the proposed Merger with Resaca is completed. The budget is as follows:

· $5.4 million at the Cato Properties;

· $7.8 million at the Panhandle Properties; and

· $0.7 million at the remaining Properties.

Of the $13.9 million budgeted development capital expenditures, we have incurred $5.1 million through September 30, 2009. Our 2010 Fiscal Year development capital program does not include the drilling of new wells. The financing of our development capital expenditures is discussed below under “Liquidity and Capital Resources.” The following reviews our capital development activity during the three-month period ended September 30, 2009 and planned activity during the balance of the 2010 Fiscal Year.

Cato Properties. As a result of increasing production response and corresponding high fluid levels from the waterflood project at the Cato Properties, we have added ten submersible pumps and plan to install additional submersible pumps as fluid levels warrant. Our 2010 Fiscal Year development capital plan includes the addition of two or three new injection wells and to enlarge the waterflood footprint from 640 acres to approximately 1,000 acres. We recently identified a new source of water located in a non-productive formation, that we believe will be able to produce 2,000 to 4,000 barrels of water per day per well. This will allow us to increase our daily water injection rate and expand the waterflood footprint. This formation has been penetrated in a number of existing wellbores in the Cato Properties. As we develop this new water source, we will be able to increase the waterflood footprint without decreasing the injection rate at our existing injectors, which should enable us to maintain production from existing producing wells. Our goal is to add 4,000 to 6,000 barrels of water injection per day to our waterflood footprint to achieve total injection of 21,000 barrels of water per day. Net production at the Cato Properties for September 2009 was 302 barrels of equivalent oil per day (“BOEPD”). Future net production from the Cato Properties is expected to be consistent with the September 2009 production rate until the total injection of 21,000 barrels of water per day is achieved, which is anticipated in the first calendar quarter of 2010.

Panhandle Properties We have retained an independent engineering firm to assist us with reservoir analysis and simulation modeling at the Cockrell Ranch unit. Based on this engineering firm’s recommendations, we established a controlled water injection pattern to gauge the effects of optimizing water injection into the highest remaining crude oil saturation intervals of the Brown Dolomite formation. We are essentially performing a “Mini-Flood” in the key target interval at the Cockrell Ranch unit. The result of this field observation, coupled with rigorous reservoir simulation modeling, is expected to demonstrate an optimal pattern for waterflooding the project with an increasingly predicable production profile. Moreover, the field observation and modeling results will improve the planning of future development programs for the remaining leases located within the Panhandle Properties. The controlled injection project caused temporarily shut-in production during most of the quarter ended September 30, 2009. All production that was shut-in for the controlled injection project was restored on September 28, 2009. The results of the controlled injection project and the accompanying reservoir simulation testing should be completed in the first calendar year of 2010 quarter.

Net production at the Panhandle Properties for September 2009 was 588 BOEPD. The controlled injection project caused temporarily shut-in production during most of the quarter ended September 30, 2009 of approximately 25 BOEPD. All production that was shut-in for the controlled injection project was restored on September 28, 2009. Production was further reduced by 15 BOEPD as the primary purchaser, Eagle Rock Field Services, L.P. (“Eagle Rock”), of our natural gas and natural gas liquids (“NGL”) experienced an unplanned plant outage from mid-August 2009 through the end of September 2009. The Eagle Rock gas plant was fully operational on October 1, 2009. During the quarter ended September 30, 2009, we constructed gathering lines to redirect natural gas production from Eagle Rock to DCP Midstream, LP (“DCP”). As of September 30, 2009, we had redirected approximately 45% of the natural gas production previously delivered to Eagle Rock, to DCP.

Desdemona Properties. During July 2009, we shut-in our Barnett Shale natural gas wells based upon the current and near-term outlook of natural gas prices and production from the Barnett Shale wells on a per-well basis. We have begun a project to return to production previously shut-in gas wells from the Duke Sand formation. The proved reserves associated these gas wells are currently classified as proved developed non-producing reserves. We plan to return 25 of these wells to production by December 2009. Production from these gas wells, including

associated natural gas liquids recovery from our gas plant, is expected to be approximately 10 MCFPD per gas well. Net production at the Desdemona Properties for September 2009 was 30 BOEPD.

Nowata Properties. We completed injecting our polymer flush during June 2009. Preliminary results have shown a two to three fold increase in the produced oil (as a percentage of total fluids produced) in our pilot observation wells. While we have seen favorable increases in production results from the pilot observation wells, we intend to perform several tests on the fluid properties produced from the pilot observation wells to gauge the effectiveness of the alkaline-surfactant-polymer (“ASP”) chemical formula. We anticipate completing the ASP Pilot performance analysis within the next three months. There are currently no proved reserves associated with the ASP Pilot. Net production at the Nowata Properties for September 2009 was 216 BOEPD.

Davenport Properties. Net production for September 2009 was 71 BOEPD.

Liquidity and Capital Resources

Pending Merger with Resaca

Liquidity

We depend on our credit agreements, as described in Note 4 to our Consolidated Financial Statements, to fund a portion of our operating and capital needs. Under the ARCA, the initial and current borrowing base, based upon our proved reserves, is $60.0 million. At September 30, 2009, our remaining available borrowing capacity under the ARCA was $13.8 million, and at November 13, 2009, our remaining available borrowing capacity was $10.0 million. Pursuant to the terms of the ARCA, our borrowing base is to be redetermined based upon our June 30, 2009 reserve report. We have submitted our reserve report and other financial information to our lenders. We have not received formal notification of any changes to our borrowing base.

At September 30, 2009, we were in compliance with the debt covenants contained in each of our credit agreements. The compliance determination for the twelve-month period ending December 31, 2009 will be the first financial covenant tests which exclude the gain from our sale of the Pantwist Properties (see Note 6 to our Consolidated Financial Statements). Based upon our nine month operating results through September 30, 2009, it appears likely that we may fall out of compliance with one or more of our financial covenants under our credit agreements as of December 31, 2009. If a combination of increased production, rising commodity prices, changes in our capital structure, the closing of our pending Merger and other actions do not occur by December 31, 2009, we anticipate not being in compliance with the covenants. In that event, we will seek covenant relief from our lenders, though there can be no assurance that we will be successful in obtaining such relief.

Our credit agreements, discussed in Note 4 to our Consolidated Financial Statements, include change of control provisions which require us to refinance the credit agreements at the close of the Merger. We are working with Resaca regarding the credit arrangements for the combined company.

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

Historically, our primary sources of capital and liquidity have been issuance of equity securities, borrowings under our credit agreements, and cash flows from operating activities. Our two credit agreements are discussed in greater detail as presented below. For the 2010 Fiscal Year, we expect to fund our operations and capital

expenditures from cash from operations, borrowings under our credit agreements and the capital markets. To develop our reserves as reported in our June 30, 2009 reserve report, we will require access to the capital markets in each of the next four years, as our projected capital expenditures are greater than projected cash flow from operations through December 2012.

Credit Agreement Covenant Compliance

At September 30, 2009, the ARCA and subordinated credit agreements contain three principal financial covenants with reconciliations of each to corresponding GAAP amounts (if necessary):

· For both credit agreements, a current ratio covenant requires us to maintain a ratio of not less than 1.00 to 1.00 for each fiscal quarter. The current ratio is calculated by dividing current assets (as defined in both credit agreements) by current liabilities (as defined in both credit agreements). Current assets include unused borrowing base under the ARCA and the aggregate availability under the subordinated credit agreement. Current liabilities exclude all current portions of long-term debt other than any current debt relating to the Series D Convertible Preferred Stock and liabilities for asset retirement obligations. Current assets and current liabilities exclude derivative assets and liabilities. At September 30, 2009, our ratio of current assets to current liabilities was 1.73 to 1.00, calculated as follows (in thousands):

	September 30, 2009
Current assets (GAAP)	$	9,014
Unused borrowing base at September 30, 2009	13,800		(1)
Less: derivative assets	(4,385		)
Modified current assets (non-GAAP)	$	18,429	(A)

Current liabilities (GAAP)	$	10,914
Less: derivative liabilities	(199		)
Less: asset retirement obligation	(88		)
Modified current liabilities (non-GAAP)	$	10,627	(B)

Modified current ratio (A) / (B)	1.73 to 1.00

(1) Represents the $60.0 million borrowing base under the ARCA at September 30, 2009, less $46.2 million long-term debt outstanding under the ARCA at September 30, 2009.

· We are required to maintain a ratio of consolidated Debt (as defined in both credit agreements) to consolidated EBITDA (as defined in both credit agreements) covenant. Under the ARCA, we are required to maintain a ratio for the four fiscal quarter period then ended of not greater than 4.00 to 1.00. Under the subordinated credit agreement, the ratio is 4.50 to 1.00. For the purposes of these ratios, Debt does not include amounts relating to our Series D Convertible Preferred Stock. At September 30, 2009, our ratio of consolidated Debt to EBITDA was 3.32 to 1.00, calculated as follows (in thousands):

	September 30, 2009
Long-term debt (GAAP)	$	61,200	(C)

	Four Fiscal Quarter
	Period Ended
	September 30, 2009
Net loss (GAAP)	$	(16,547	)(2)
Depletion, depreciation and amortization	5,771
Interest expense, net	546
Income tax benefit	(8,028		)(2)
Other adjustments (non-GAAP)	36,708		(3)
EBITDA (non-GAAP)	$	18,450	(D)

Debt to EBITDA (C) / (D)	3.32 to 1.00

(2) Through the quarter ending September 30, 2009, EBITDA includes the $19.2 million pre-tax gain on the sale of Pantwist LLC.

(3) As defined in both credit agreements, other items are considered in the calculation of EBITDA, including impairment of long-lived assets and goodwill, stock-based compensation, accretion of discount on asset retirement obligations, exploration expense, settlements of fire litigation lawsuits and non-cash items included in the computation of income from discontinued operations.

· We are required to maintain a ratio of consolidated EBITDA (as defined in both agreements) to consolidated Interest Expense (as defined in both agreements) covenant for the four fiscal quarter period then ended. Under the ARCA, we are required to maintain a ratio of not less than 3.00 to 1.00. Under the subordinated credit agreement, our ratio is 2.50 to 1.00. At September 30, 2009, our ratio of consolidated EBITDA to consolidated Interest Expense ratio was 7.25 to 1.00, calculated as follows (in thousands):

	Four Fiscal Quarter
	Period Ended
	September 30, 2009
EBITDA (non-GAAP) (see reconciliation above)	$	18,450	(E)

Interest expense	$	546
Capitalized interest	1,425
Cash payment of preferred stock dividends	933
Less: amortization of debt issuance costs	(358		)
Interest expense (non-GAAP)	$	2,546	(F)

EBITDA to interest expense (E) / (F)	7.25 to 1.00

Both of our credit agreements also contain customary events of default that would permit our lenders to accelerate the debt under both credit agreements if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, breach of covenants, failure to make mandatory prepayments in the event of borrowing base deficiencies, events of bankruptcy, dissolution, the occurrence of one or more unstayed judgments in excess of $1,000,000 and defaults upon other obligations, including obligations under the subordinated credit agreement. At September 30, 2009, we were in compliance with all of our covenants and had not committed any acts of default under both the ARCA and the subordinated credit agreements.

Based on our current estimates of income and expenses, it appears likely that we may fall out of compliance with one or more of our financial covenants under the ARCA and/or the Subordinated Credit Agreement as of December 31, 2009. We are currently in discussions with our lenders regarding this possibility and potential solutions, including without limitation, obtaining waivers from the applicable covenants, entering into amendments to our credit agreements or raising additional capital through equity issuances. If we are unable to obtain such waivers, to negotiate such amendments or to obtain necessary funding from operations or outside capital raising activities, we could default on our obligations under one or both of our credit agreements, which default, if not cured or waived, could result in the acceleration of all indebtedness outstanding under our credit agreements.

Results of Operations

For the quarter ended September 30, 2009 (“current quarter”), we had a loss applicable to common stock of $4.0 million, which was a $15.8 million decrease as compared to the $11.8 million income applicable to common stock incurred for the quarter ended September 30, 2008 (“prior year quarter”). Items contributing to the $15.8 million earnings decrease were lower gain on derivatives of $24.2 million and lower operating revenues of $5.7 million. Partially offsetting the earnings decrease were lower operating expenses of $2.5 million, reduced loss on discontinued operations of $0.9 million and lower preferred stock dividends of $0.5 million.

These items will be addressed in the following discussion.

Operating Revenues

The table below summarizes our operating revenues for the quarters ended September 30, 2009 and 2008.

	Quarter ended September 30,				Increase
	2009		2008		(Decrease)
Operating Revenues (in thousands)	$	5,264	$	10,931	$	(5,667	)
Sales
· Crude Oil (MBbls)	72		72		—
· Natural Gas (MMcf)	159		195		(36		)
· Total (MBOE)	99		105		(6		)
Average Realized Price
· Crude Oil ($/ Bbl)	$	61.20	$	111.88	$	(50.68	)
· Natural Gas ($/ Mcf)	$	5.24	$	14.04	$	(8.80	)

Operating Revenues and Commodity Derivative Settlements (in thousands)	$	7,115	$	10,379	$	(3,264	)

Average Adjusted Price (includes commodity derivative settlements)
· Crude Oil ($/ Bbl)	$	71.38	$	106.25	$	(34.87	)
· Natural Gas ($/ Mcf)	$	12.24	$	13.30	$	(1.06	)

The current quarter operating revenues of $5.3 million are $5.6 million lower as compared to the prior year quarter of $10.9 million. The $5.6 million reduction is primarily attributable to lower prices received for crude oil and natural gas sales of $3.7 million and $1.4 million, respectively, and lower natural gas sales volumes which reduced revenues by $0.5 million. The lower natural gas sales occurred at the Panhandle Field (26 MMcf) and the Desdemona Field (10 MMcf).

The impact of lower prices for crude oil and natural gas sales, as discussed above, is partially mitigated by commodity derivative settlements received during the current quarter as presented in the preceding table. As discussed in Note 5 to our Consolidated Financial Statements, if crude oil and natural gas NYMEX prices are lower than derivative floor prices, we will be reimbursed by our counterparty for the difference between the NYMEX price and floor price (i.e. realized gain). Conversely, if crude oil and natural gas NYMEX prices are higher than the

derivative ceiling prices, we will pay our counterparty for the difference between the NYMEX price and ceiling price (i.e. realized loss).

Crude Oil Sales. Our current quarter crude oil sales approximated our prior year quarter sales. Increased production from our Cato Properties of 2 MBbls was offset by lower sales from our Panhandle Properties as we had temporary shut-in production at the Cockrell Ranch waterflood due to the controlled injection project surveillance, as previously discussed under the “Drilling Capital Development and Operating Activities Update.” All Cockrell Ranch production that had been shut-in for the controlled injection project was restored on September 28, 2009.

Natural Gas Sales. The lower natural gas sales during the current quarter occurred at the Panhandle Field (26 MMcf) and the Desdemona Field (10 MMcf). At the Panhandle Field, lower natural gas sales resulted from the controlled production project at Cockrell Ranch waterflood, as previously discussed, and one of our gas purchasers experienced an unplanned plant outage from mid-August 2009 through the end of September 2009, which resulted in reduced natural gas and NGL sales. At the Desdemona Field, during July 2009, we shut-in our Barnett Shale natural gas wells based upon the current and near-term outlook of natural gas prices.

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 levels of impurities in the oil. 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. As previously discussed, we have commodity derivatives in place that mitigate future price risk.

We expect to grow sales through our development plans as previously discussed under “Overview—Development Capital Expenditures and Operating Activities Update.”

Operating Expenses

For the current quarter, our total operating expenses were $9.8 million, which is a decrease of $2.4 million as compared to the prior year quarter of $12.2 million. The $2.4 million improvement resulted from lower general and administrative of $1.3 million, reduced lease operating expenses of $0.7 million and decreased production and ad valorem taxes of $0.6 million.

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 $4.4 million, which is $0.7 million lower than the prior year quarter of $5.1 million. The $0.7 million decrease resulted primarily from reduced service rates negotiated with vendors and the shut-in of our Barnett Shale natural gas wells, as previously discussed under “Operating Revenues,” which reduced LOE by $0.2 million. Partially offsetting these LOE cost reductions were increased LOE at the Cato Properties of $0.3 million to support higher levels of activity, as previously discussed under “Operating Revenue.”

For the current quarter, our LOE per BOE, based on production, was $38.73, which is an improvement of $6.90 as compared to $45.63 for the prior year quarter. In general, secondary and tertiary LOE is higher than LOE for companies developing primary production because our fields are more mature and typically produce less oil and more water. We expect LOE to decrease during the 2010 Fiscal Year as we realize the continued benefit lower service rates negotiated with vendors, and we expect LOE per BOE to decrease as production increases from the waterflood and EOR development activities we have implemented and are implementing as discussed under the “Drilling Capital Development and Operating Activities Update.”

Production and Ad Valorem Taxes

For the current quarter, our production and ad valorem taxes were $0.5 million, which is $0.6 million lower than the prior year quarter of $1.1 million. The $0.6 million decrease resulted from lower production taxes of $0.4 million due to lower operating revenues and reduced ad valorem taxes of $0.2 million due to lower property tax valuations by taxing authorities for the 2009 calendar year. Our production taxes as a percent of operating revenues for the current quarter were of 6.3% was comparable to the prior year quarter of 7.0%.

General and Administrative Expenses

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 $3.6 million, which is $1.3 million lower than the prior year quarter of $4.9 million. The $1.3 million expense reduction resulted from lower payroll and benefits costs of $0.3 million, reduced stock-based compensation costs of $0.6 million and reduced legal costs of $1.0 million, partially offset by increased costs related to the Merger of $0.8 million, as discussed in Note 2 to our Consolidated Financial Statements.

The reduced payroll and benefits costs resulted from workforce reductions we implemented during the quarter ended March 31, 2009, which eliminated 25% of our home office staff and is estimated to reduce payroll and benefits costs by $0.8 million annually. The lower stock-based compensation costs are directly related to reduced issuances of stock options and restricted stock. Legal cost reduction occurred as we have settled all but one of our fire litigation claims during the fiscal year ended June 30, 2009 as discussed in Note 11 to our Consolidated Financial Statements, we expect significant decreases in future quarters’ legal expenses.

Depletion and Depreciation

For the current quarter, our depletion and depreciation expense was $1.3 million, an increase of $0.1 million as compared to the prior year quarter expense of $1.2 million. This includes depletion expense pertaining to our oil and natural gas properties, and depreciation expense pertaining to our field operations vehicles and equipment, natural gas plant, office furniture and computers. The increase is due to higher depreciation of non-oil and gas properties assets, partially offset by lower depletion costs due to lower crude oil and natural gas sales volumes (net) as previously discussed under “Operating Revenues.” For the current quarter, our depletion rate pertaining to our oil and gas properties was $10.60 per BOE, as compared to the prior year quarter rate of $10.36 per BOE.

Interest Expense and Other

For the current and prior year quarters, we incurred interest expense of $0.2 million and $0.1 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 4 to our Consolidated Financial Statements. The interest expense for the current and prior year quarters was reduced by $0.5 million and $0.3 million, respectively, for interest cost that was capitalized to the waterflood and ASP projects discussed under the “Overview - Development Capital Expenditures and Operating Activities Update.” We incurred higher interest costs during the current year quarter due to higher outstanding debt balances.

Gain (Loss) on Derivatives

As discussed in Note 5 to our Consolidated Financial Statements, we have entered into financial derivatives contracts for our commodity sales and interest expense. For the current quarter, we recorded a loss on derivatives of $0.5 million as compared to a gain of $23.7 million for the prior year quarter. The current quarter loss of $0.5 million consisted of an unrealized loss of $2.3 million and a realized gain on settlements of derivative contracts of $1.8 million.

The realized gain primarily pertains to the realization of commodity settlements, as crude oil and natural gas NYMEX prices were lower than the floor prices.

The unrealized loss for the current quarter reflects the fair value of the commodity derivatives as of September 30, 2009 as compared to June 30, 2009. By their nature, these commodity derivatives can have a highly volatile impact on our earnings. A five percent change in the prices for our commodity derivative instruments could impact our pre-tax earnings by approximately $0.3 million.

Income Tax Benefit (Expense)

For the current quarter, we had an income tax benefit of $1.6 million, as compared to an income tax expense for the prior year quarter of $8.1 million. The prior year quarter tax amount included taxes related to discontinued operations as shown in Note 6 to our Consolidated Financial Statements. The decreased income taxes for the current quarter, as compared to the prior year quarter, resulted from the decrease in taxable income. The effective income tax rates for the current and prior year quarters were 31% and 39%, respectively.

Loss from Discontinued Operations

For the current quarter, we had no income from discontinued operations, as compared to a $0.9 million loss for the prior year quarter. The prior year quarter loss pertains to our divestitures of the Pantwist, LLC and Corsicana Properties, as discussed in Note 6 to our Consolidated Financial Statements.

Preferred Stock Dividend

The preferred stock dividend for the current quarter of $0.5 million was a decrease of $0.4 million from $0.9 million for the prior year quarter. The decrease is attributable to our November and December 2008 repurchases of preferred stock. Due to the repurchases, our quarterly preferred stock dividends will be approximately $0.5 million per quarter of which 59% will be PIK, with the balance paid in cash.

New Accounting Pronouncements

In June 2009, the FASB issued a standard that established the FASB Accounting Standards CodificationTM (“ASC”) and amended the hierarchy of GAAP such that the ASC became the single source of authoritative nongovernmental GAAP. The ASC did not change current GAAP, but was intended to simplify user access to all authoritative GAAP by providing all the authoritative literature related to a particular topic in one place. All previously existing accounting standard documents were superseded and all other accounting literature not included in the ASC is considered non-authoritative. New accounting standards issued subsequent to June 30, 2009 are communicated by the FASB through Accounting Standards Updates (ASUs). The ASC became effective for us on July 1, 2009. This standard did not have an impact on our financial position, results of operations or cash flows. Throughout the notes to the consolidated financial statements, references that were previously made to various former authoritative GAAP pronouncements have been conformed to the appropriate section of the ASC.

In December 2007, the FASB issued ASC 805 (formerly SFAS No. 141 (revised 2007), Business Combinations). Among other things, ASC 805 establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. ASC 805 is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted ASC 805 on July 1, 2009. This standard will change our accounting treatment for prospective business combinations.

In December 2007, the FASB issued ASC 810 (formerly SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51). ASC 810 establishes accounting and reporting

standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted SFAS No. 160 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In March 2008, the FASB issued ASC 815 (formerly SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement 13). ASC 815 expands the required disclosures to discuss the uses of derivative instruments; the accounting for derivative instruments and related hedged items, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In June 2008, the FASB issued ASC 260 (formerly EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities). ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of earnings per share under the two-class method. Under ASC 260, share-based payment awards that contain nonforfeitable rights to dividends are “participating securities” and, therefore, should be included in computing earnings per share using the two-class method. ASC 260 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 260 on July 1, 2009. The effect of adopting ASC 260 increased the number of shares used to compute earnings per share; however, the adoption of ASC 260 did not have a material impact on our financial position, results of operations or cash flows.

In December 2008, the FASB issued ASC 815 (formerly EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock). ASC 815 affects companies that have provisions in their securities purchase agreements (for warrants and convertible instruments) that reset conversion prices based upon new issuances by companies at prices below the current conversion price of said instrument. Warrants and convertible instruments with such provisions will require the embedded derivative instrument to be bifurcated and separately accounted for as a derivative. Subject to certain exceptions, our Preferred Stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. ASC 815 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows since the reset conversion provision did not meet the definition of a derivative since it was not readily net-cash settled.

Item 4T. Controls and Procedures.

As of the end of the period covered by this report, our management conducted an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness 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, as of September 30, 2009, that our disclosure controls and procedures were 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) recorded, processed, summarized and reported, within the time periods specified in the Securities and

Exchange Commission’s rules and forms and (2) accumulated and communicated to management, including our chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure.

During the quarter ended September 30, 2009, there was no change in our internal control over financial reporting 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.

See Note 11 to our Consolidated Financial Statements which is incorporated into this “Item 1. Legal Proceedings” by reference.

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

The following shares of our common stock were delivered to us during the quarter ended September 30, 2009 from S. Jeffrey Johnson, Patrick McKinney and Michael Ricketts, pursuant to the terms of the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, to satisfy tax withholding obligations relating to the vesting of restricted stock awards:

Period	Total Number of Shares (or Units) Purchased	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1, 2009 through July 31, 2009	24,686	$	0.85	—	—

August 1, 2009 through August 31, 2009	—	—		—	—

September 1, 2009 through September 30, 2009	—	$	—	—	—

Total	24,686	$	0.85	—	—

Item 6. Exhibits.

Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on October 1, 2009.
10.1		Temporary Waiver of Benefits by and between Cano Petroleum, Inc. and S. Jeffrey Johnson effective as of October 28, 2008, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on July 8, 2009.
10.2*		Gas Purchase Agreement by and between W.O. Operating Company Ltd. and DCP Midstream, L.P. effective on July 1, 2009.
10.3		Stock Voting Agreement, dated as of September 29, 2009 by and between Cano Petroleum, Inc. and D.E. Shaw Laminar Portfolios, L.L.C., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on October 1, 2009.
10.4		Separation Agreement and Release, dated as of September 29, 2009 by and among Cano Petroleum, Inc., Resaca Exploitation, Inc. and S. Jeffrey Johnson, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on October 1, 2009.
10.5		Separation Agreement and Release, dated as of September 29, 2009 by and among Cano

		Petroleum, Inc., Resaca Exploitation, Inc. and Benjamin L. Daitch, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on October 1, 2009.
31.1*		Certification by Chief Executive Officer, required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act, promulgated pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification by Chief Financial Officer, required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act, promulgated pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification by Chief Executive Officer, required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code, promulgated pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification by Chief Financial Officer, required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code, promulgated pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CANO PETROLEUM, INC.

Date: November 13, 2009	By:	/s/ S. Jeffrey Johnson
		S. Jeffrey Johnson
		Chief Executive Officer


Date: November 13, 2009	By:	/s/ Benjamin Daitch
		Benjamin Daitch
		Senior Vice-President and Chief Financial Officer

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