Edgar Filing: CANO PETROLEUM, INC

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K


(Mark One)

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

For the fiscal year ended: June 30, 2009 OR

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

COMMISSION FILE NUMBER: 001-32496

Cano Petroleum, Inc.
(Exact name of Registrant as specified in its charter)


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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No ý

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

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 ý No o

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

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

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


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

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

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of December 31, 2008, was approximately $16.4 million. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

The number of shares outstanding of the registrant's common stock, par value $.0001 per share, as of September 28, 2009 was 45,570,147 shares.

DOCUMENTS INCORPORATED BY REFERENCE


Document		Part of the Form 10-K into which the document is incorporated
Our definitive proxy statement relating to our 2009 annual meeting of stockholders, to be filed not later than 120 days after the end of the fiscal year covered by this report		Part III

Table of Contents

TABLE OF CONTENTS


PART I		1
Items 1 and 2. Business and Properties		1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties (see Items 1 and 2. Business and Properties)	24
Item 3.	Legal Proceedings	24
Item 4.	Submission of Matters to a Vote of Security Holders	30
PART II		31
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	33
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	61
Item 9A.	Controls and Procedures	61
Item 9B.	Other Information	64
PART III		64
Item 10.	Directors, Executive Officers and Corporate Governance.	64
Item 11.	Executive Compensation.	64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accountant Fees and Services	64
PART IV		65
Item 15.	Exhibits and Financial Statement Schedules	65

Table of Contents

PART I

Items 1 and 2. Business and Properties.

Introduction

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

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

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

Our Properties

Cato Properties. Cano Petro of New Mexico, Inc., our wholly-owned subsidiary, acquired certain oil and gas properties in the Permian Basin in March 2007 for approximately $8.4 million, after purchase price adjustments. The purchase price consisted of approximately $6.6 million in cash and 404,204 shares of Cano restricted common stock. The Cato Properties include roughly 20,000 acres across three fields in Chavez and Roosevelt Counties, New Mexico. The prime asset is the roughly 15,000 acre Cato Field, which produces from the historically prolific San Andres formation, which has been successfully waterflooded in the Permian Basin for over 30 years. The Cato Properties did not have full-scale waterflood development prior to our acquisition. Proved reserves as of June 30, 2009 attributable to the Cato Properties were 16.0 MMBOE, of which 1.9 MMBOE were PDP, 0.5 MMBOE were PDNP and 13.6 MMBOE were PUD. Net production for the month of June 2009 was 316 BOEPD. Our working and net revenue interests are 97% and 82%, respectively.

Panhandle Properties. In November 2005, through our acquisition of W.O. Energy of Nevada, Inc., we acquired 480 producing wells, 40 water disposal wells and 380 idle wells on approximately 20,000 acres in Carson, Gray and Hutchinson Counties, Texas. Also, included in the acquisition were 10 workover rigs and related equipment. The adjusted purchase price was approximately $56.6 million composed of $48.4 million of cash and 1,791,320 shares of common stock. The Panhandle Properties did not have full-scale waterflood development prior to our acquisition. In January 2008, we sold the workover rigs for $3.0 million. We are progressing with the execution of our waterflood development plans at the Cockrell Ranch and Harvey Units. We have received approval of the waterflood permits at the Pond Lease and at the Olive-Cooper Lease, two of our planned mini-floods. Proved reserves as of June 30, 2009 attributable to the Panhandle Properties were 28.9 MMBOE, of which 3.5 MMBOE were PDP and 25.4 MMBOE were PUD. Net production for the month of June 2009 was 627 BOEPD. Our working and net revenue interests are 100% and 81%, respectively.

Desdemona Properties. In March 2005, in connection with our acquisition of Square One Energy, Inc. for $7.6 million, consisting of $4.0 million cash and 888,888 shares of our common stock, we acquired a 100% working interest in 11,068 acres in mature oil fields in central Texas. These properties were not previously waterflooded and have mineral rights to the Barnett Shale and Duke Sands formations. Proved reserves as of June 30, 2009 attributable to the Desdemona Properties were

Table of Contents

1.4 MMBOE, of which 0.1 MMBOE were PDP and 1.3 MMBOE were PDNP. Net production for the month of June 2009 was 54 BOEPD. Our working and net revenue interests are 100% and 83%, respectively.

Nowata Properties. In September 2004, we acquired more than 220 wells producing from the Bartlesville Sandstone in Nowata County, Oklahoma, for approximately $2.6 million cash. The Nowata Properties were previously waterflooded. Proved reserves as of June 30, 2009 attributable to the Nowata Properties were 1.5 MMBOE, all of which are PDP. Net production for the month of June 2009 was 229 BOEPD. Our working and net revenue interests are 100% and 85%, respectively.

Davenport Properties. In May 2004, we acquired properties in Lincoln County, Oklahoma for 5,165,000 shares of our common stock and $1.7 million cash. Proved reserves as of June 30, 2009 attributable to the Davenport Properties were 1.3 MMBOE, of which 0.7 MMBOE were PDP and 0.6 MMBOE were PDNP. Net production for the month of June 2009 was 79 BOEPD. Our working and net revenue interests are 100% and 78%, respectively.

Planned Development Program

We believe that our portfolio of oil and natural gas properties provides opportunities to apply our operational strategy. As of June 30, 2009, we had proved reserves of 49.1 MMBOE, of which 7.7 MMBOE were PDP, 2.4 MMBOE were PDNP, and 39.0 MMBOE were PUD.

We plan to grow by developing our existing oil and natural gas properties by applying water, gas and/or chemical flooding and other EOR techniques. We will also continue to evaluate potential acquisition targets that are consistent with our operational strategy. These development activities are more clearly described under "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Drilling Capital Development and Operating Activities Update."

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

Industry Conditions

We believe significant acquisition opportunities exist and will continue to exist as major energy companies and larger independents continue to focus their attention and resources toward the discovery and development of large fields. Management expects the trend of the past several years to continue where larger companies have been divesting mature onshore oilfields and more recently the disruptions caused by volatility in the commodity, capital and credit markets will force companies to divest assets for liquidity purposes. These factors should provide ample opportunities for small independent companies to acquire and exploit mature U.S. fields.

Our Strategy

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

Table of Contents

•: Acquire Strategic Assets. We seek to acquire low-cost assets with reserves suitable for EOR techniques in the onshore U.S. We will continue to target acquisitions that meet our engineering and operational standards in a financially prudent manner.
•: Drill Known Formations. Our portfolio is composed of mature fields with proved primary and/or secondary reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on wildcat exploration drilling of new formations and the high degree of speculation associated with making new discoveries, but the application of commonly used secondary and/or tertiary recovery methods to increase production and reserves.

December 2008 Financing

On December 17, 2008, we finalized a new $120.0 million Amended and Restated Credit Agreement (the "ARCA") with Union Bank of North America, N.A. ("UBNA," f/k/a Union Bank of California, N.A.) and Natixis. UBNA is the Administrative Agent and Issuing Lender of the ARCA. The initial and current borrowing base, based upon our proved reserves, is $60.0 million.

On December 17, 2008, we finalized a new $25.0 million Subordinated Credit Agreement among Cano, the lenders party thereto and UnionBanCal Equities, Inc ("UBE") as Administrative Agent (the "Subordinated Credit Agreement"). The current availability under the Subordinated Credit Agreement is $15.0 million. An additional $10.0 million can be made available at the lenders' sole discretion.

These two credit agreements are discussed in greater detail "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreements."

July 2008 Financing

On July 1, 2008, we completed the sale of 7,000,000 shares of our common stock through an underwritten offering at a share price of $8.00 per share ($7.75 net to us) resulting in net proceeds of approximately $53.9 million after underwriting discounts and commissions and expenses.

We used the net proceeds from the offering to pay down debt. We subsequently made borrowings against our borrowing base in order to finance our development activities in certain core areas such as the Panhandle and Cato Properties and general corporate purposes. These development activities are more clearly defined later under "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Drilling Capital Development and Operating Activities Update."

Proved Reserves

The following table summarizes proved reserves as of June 30, 2009 and was prepared according to the rules and regulations of the Securities and Exchange Commission ("SEC").



Oil—MBbls	1,237	366	14,867	20,888	1,413	38,771
Gas—MMcf	425	6,196	6,619	47,913	800	61,953
Oil Equivalent (MBOE)	1,308	1,399	15,970	28,873	1,547	49,097

Our proved oil and natural gas reserves as of June 30, 2009 have been prepared by Miller and Lents, Ltd., international oil and gas consultants. As defined in the SEC rules, proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if

Table of Contents

economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injections) are included in the "proved" classification when successful testing by a pilot project, or the operations of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling, production history and from changes in economic factors.

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

At June 30, 2009, our proved reserves equated to 49.1 MMBOE of proved reserves, consisting of 7.7 MMBOE (16%) of PDP reserves, 2.4 MMBOE (5%) of PDNP reserves and 39.0 MMBOE (79%) of PUD reserves.

Reserves were estimated using crude oil and natural gas prices and production and development costs in effect on June 30, 2009. On June 30, 2009, crude oil and natural gas prices were $69.89 per barrel and $3.71 per MMBtu, respectively. The values reported may not necessarily reflect the fair market value of the reserves.

Production/Operating Revenues

The following table presents sales, unit prices and average unit costs for the years ended June 30, 2009, 2008, and 2007.

		Years Ended June 30,

		2009		2008		2007
Operating Revenues (1): (000's)		$	25,409	$	34,650	$	20,651
Sales:
	Oil (MBbls)		309		249		223
	Gas (MMcf)		776		908		824
	MBOE		438		401		360
Average Price (1):
	Oil ($/Bbl)	$	62.17	$	94.08	$	61.96
	Gas ($/Mcf)	$	7.57	$	11.99	$	8.29
	$/BOE	$	57.23	$	85.72	$	57.31
Expense (per BOE):
Lease operating		$	42.96	$	33.14	$	24.24
Production and ad valorem taxes		$	5.37	$	6.13	$	4.70
General and administrative expense, net		$	43.68	$	37.10	$	35.06
Depreciation and depletion		$	13.05	$	9.74	$	8.89
Total		$	105.06	$	86.10	$	72.89

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

Table of Contents

Productive Wells and Acreage

The following table shows our gross and net interests in productive oil and natural gas working interest wells as of August 28, 2009. Productive wells include wells currently producing or capable of production.

Gross(1)			Net(2)

Oil	Gas	Total	Oil	Gas	Total
1,846	88	1,934	1,836	88	1,924

(1): "Gross" refers to wells in which we have a working interest.
(2): "Net" refers to the aggregate of our percentage working interest in gross wells before royalties or other payout, as appropriate.

We operate all of the gross producing wells presented above. As of August 28, 2009, we had 17 wells containing multiple completions.

On August 28, 2009, we had total acreage of 55,847 gross acres and 55,247 net acres, all of which was considered developed acreage. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage under lease, permit, contract or option that is not in the spacing unit for a producing well, including leasehold interests identified for exploitation drilling.

Drilling Activity

The following table shows our drilling activities on a gross basis for the years ended June 30, 2009, 2008 and 2007. We own 100% working interests in all wells drilled.

			Years Ended June 30,

			2009		2008		2007
			Gross(1)		Gross(1)		Gross(1)
Exploratory
	Oil(3)			4		—		22
Development
	Gas(2)			—		4		19
	Oil(3)			14		62		39
	Abandoned(4)			—		2		—

		Total		18		68		80

(1): "Gross" is the number of wells in which we have a working interest.
(2): "Gas" means natural gas wells that are either currently producing or are capable of production.
(3): "Oil" means producing oil wells.
(4): "Abandoned" means wells that were dry when drilled or were abandoned without production casing being run.

Present Activities

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

Table of Contents

Delivery Commitment

At June 30, 2009, we had no delivery commitments with our purchasers and currently have no delivery commitments.

Title/Mortgages

Our oil and natural gas properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions as well as mortgage liens in accordance with our credit agreements. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business. See Note 6 to our Consolidated Financial Statements regarding the mortgages that we have granted under the credit agreements on all of our oil and natural gas properties.

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

Acquisitions

We regularly pursue and evaluate acquisition opportunities (including opportunities to acquire oil and natural gas properties and related assets or entities owning oil and natural gas properties or related assets, and opportunities to engage in mergers, consolidations or other business combinations with entities owning oil and natural gas properties or related assets) and at any given time may be in various stages of evaluating such opportunities. Such stages include: internal financial and oil and natural gas property analysis, preliminary due diligence, the submission of an indication of interest, preliminary negotiations and negotiation of a letter of intent or negotiation of a definitive agreement.

Competition

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

Customers

We sell our crude oil and natural gas production to multiple independent purchasers pursuant to contracts generally terminable by either party upon thirty days' prior written notice to the other party. During the year ended June 30, 2009, 10% or more of our total revenues were attributable to five customers accounting for 32% (Valero Marketing Supply Co.), 18% (Coffeyville Resources Refinery and Marketing, LLC), 15% (Plains Marketing, LP), 13% (Eagle Rock Field Services, LP), and 10% (DCP Midstream, LP) of total operating revenue, respectively. On March 31, 2009, we received notice from Eagle Rock Field Services, L.P. ("Eagle Rock") that it would be terminating its gas purchase agreement with us due to the decrease in oil and natural gas prices unless we agreed to accept Eagle Rock's proposed new pricing terms. We were unable to reach a new agreement with Eagle Rock. Beginning on June 2, 2009, we began selling natural gas production to Eagle Rock on a sliding scale based upon the volume of fluid it sells per each delivery point for both natural gas and NGLs. On August 4, 2009, we entered into a new Gas Purchase Contract (the "DCP Agreement") with DCP

Table of Contents

Midstream, L.P. ("DCP") effective on July 1, 2009, which supersedes the previous gas purchase contract, as amended, with DCP. Previously, all of our Panhandle Properties' leases and wells were dedicated to DCP and Eagle Rock. The new DCP Agreement dedicates all of our Panhandle Properties' leases and wells to DCP. Subject to certain conditions, the term of the DCP Agreement runs until April 30, 2016 and, unless terminated upon 60 days' prior notice, continues thereafter on a year-to-year basis. Pursuant to the terms of the DCP Agreement, we will be paid on a sliding scale based upon the volume of NGLs and natural gas it sells per each delivery point. We will continue to sell, on a month-to-month basis, natural gas and NGLs in the Texas Panhandle to Eagle Rock until such time as any given well is added to new delivery points on the DCP pipeline. Revenue enhancements under the DCP Agreement will offset the effect of volumes sold to Eagle Rock.

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

In the event that one or more of these significant purchasers ceases doing business with us, we believe that there are potential alternative purchasers with whom we could establish new relationships and that those relationships would result in the replacement of one or more lost purchasers. We would not expect the loss of any single purchaser to have a material adverse effect on our operations. However, the loss of a single purchaser could potentially reduce the competition for our crude oil and natural gas production, which could negatively impact the prices we receive.

Governmental Regulation

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

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

Table of Contents

Transportation and Sale of Natural Gas

Our natural gas sales were approximately 29% of our total sales during the year ended June 30, 2009. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates and various other matters, by the Federal Energy Regulatory Commission ("FERC"). Federal wellhead price controls on all domestic natural gas were terminated on January 1, 1993, and none of our natural gas sales prices are currently subject to FERC regulation. We cannot predict the impact of future government regulation on our natural gas operations.

Insurance

Our insurance policies currently provide for $1,000,000 general liability coverage for bodily injury and property damage including pollution, underground resources, blow-out and cratering. In addition, we have $1,000,000 coverage for our contractual obligations to our service contractors using their equipment downhole if it is damaged as a result of a blow-out. We have an "Owned-Hired and Non-Owned" commercial automobile liability limit of $1,000,000. We also have secured $50,000,000 umbrella coverage in excess of the general liability and automobile liability. Additionally, we have a $2,000,000 policy for control of well, redrill, and pollution on drilling wells and a $1,000,000 policy for control of well, redrill and pollution on producing wells.

Environmental Regulations

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

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

Occupational Safety Regulation

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

Table of Contents

Federal, State or Native American Leases

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

Employees

As of September 25, 2009, we and our wholly-owned subsidiaries had 63 employees, all of whom are full-time employees. None of our employees are represented by a union. We have never experienced an interruption in operations from any kind of labor dispute, and we consider the working relationships among the members of our staff to be generally good.

Principal Executive Offices

Our principal executive offices are located at The Burnett Plaza, 801 Cherry Street, Suite 3200, Fort Worth, TX 76102. Our principal executive offices consist of 24,303 square feet and are subject to a lease that expires on June 2014. See Note 17 to our Consolidated Financial Statements regarding our lease payments now and in the future.

Internet Address/Availability of Reports

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

Table of Contents

Glossary of Selected Oil and Natural Gas Terms

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

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

"BOEPD" BOE per day.

"BTU." British Thermal Unit.

"BWIPD." Barrels of water injected per day.

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

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

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

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

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

"MBbl." One thousand Bbls.

"MBOE." One thousand BOE.

"Mcf." One thousand cubic feet of natural gas.

"MMBOE." One million BOE.

"MMcf." One million cubic feet of natural gas.

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

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

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

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

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

Table of Contents

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

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

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

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

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

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

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

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

"U.S." The United States of America.

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

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

Table of Contents

Item 1A. Risk Factors.

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

Risks Related to Our Industry

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

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

•: worldwide and domestic demands and supplies of oil and natural gas;
•: weather conditions;
•: the price and availability of alternative fuels;
•: the availability of pipeline capacity;
•: the price and level of foreign imports;
•: domestic and foreign governmental regulations and taxes;
•: the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•: political instability or armed conflict in oil-producing regions; and
•: the overall economic environment.

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

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

Oil and natural gas operations are subject to various and numerous federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, spacing of wells, injection of substances, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. Certain federal, state and local laws and regulations applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations, exist for the purpose of protecting the human health and the environment. The transportation and storage of refined products include the risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies and private parties

Table of Contents

for natural resources damages, personal injury, or property damages and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined and unrefined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. As a result, we may incur substantial expenditures and/or liabilities to third parties or governmental entities which could have a material adverse effect on us.

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

The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition of, exploration for and development of, crude oil and natural gas reserves.

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

•: our proved reserves;
•: the level of oil and natural gas we are able to produce from existing wells;
•: the prices at which oil and natural gas are sold; and
•: our ability to acquire, locate and produce new reserves.

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

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

Risks Related to Our Business

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

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

•: develop our oil and natural gas properties, including the successful application of EOR technologies, to the point at which oil and natural gas are being produced in commercially viable quantities;
•: contract with third parties regarding services necessary to develop our oil and natural gas properties;
•: contract with transporters and purchasers of our oil and natural gas production;
•: maintain access to funds to pursue our capital-intensive business plan;
•: comply with all applicable laws and regulations;
•: implement and successfully execute our business strategy;

Table of Contents

•: find and acquire rights in strategic oil and natural gas properties;
•: respond to competitive developments and market changes; and
•: attract, retain and motivate qualified personnel.

There can be no assurance that we will be successful in undertaking such activities. Our failure to successfully undertake most of the activities described above could materially and adversely affect our business, prospects, financial condition and results of operations. There can be no assurance that sales of our oil and natural gas production will be able to sustain profitability in any future period.

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

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

We will need to obtain funds from additional financings or other sources for our business activities. If new capital is raised in the form of equity, your ownership and voting rights in our securities may be diluted. In addition, if we do not receive these funds, we would need to reduce, delay or eliminate some of our expenditures.

We have sustained recurring losses and negative cash flows from operations. Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of equity financings, borrowings under our credit agreements, the sale of assets and cash flows from operating activities. As of June 30, 2009, we had approximately $0.4 million of cash and cash equivalents available to fund operations. We review cash flow forecasts and budgets periodically. We believe that we currently have sufficient cash and financing capabilities to meet our funding requirements until the end of Fiscal Year 2010. However, we have experienced, and continue to experience, negative operating margins and negative cash flows from operations. See Note 2 to our Consolidated Financial Statements.

We will need to raise additional capital to accomplish our business plan over the next several years. We expect to seek to obtain additional funding through debt and/or equity financing in the capital markets. Equity financings may result in dilution to existing stockholders and may involve securities that have rights, preferences or privileges that are senior to our common stock. There can be no assurance as to the availability or terms upon which such financing and capital might be available.

If adequate funds are not available, we may be required to reduce, delay or eliminate development expenditures, seek to enter into a business combination transaction with other companies or sell assets. These transactions may not be available to us when needed or on terms acceptable or favorable to us.

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

This annual report contains estimates of our proved reserves. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas

Table of Contents

prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Approximately 79% of our total proved reserves as of June 30, 2009 consisted of undeveloped reserves, and those reserves may not ultimately be developed or produced.

Approximately 79% of our total proved reserves as of June 30, 2009 were undeveloped. While we plan to develop and produce all of our proved reserves, these reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, nor at the costs we have budgeted, or at all. As of June 30, 2009, estimated development costs for our PDNP and PUD reserves were approximately $4.6 million and $328.0 million, respectively, through 2016.

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

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

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

Our historical growth has been due in part to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. We expect acquisitions to also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from waterflood and EOR techniques, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform reviews of acquired properties which we believe are generally consistent with industry practices. However, such reviews will not reveal all existing or potential problems. In addition, these reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Additionally, we do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves.

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

Table of Contents

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

The new wells we drill or participate in, whether undertaken in primary drilling or utilizing waterflood or EOR techniques may not be productive and we may not recover all or any portion of our investment. The engineering data and other technologies we use do not allow us to know conclusively, prior to beginning a project, that crude oil or natural gas is present in the reservoir or that those reserves can be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to generate an economic return. Further, our drilling and other operations may be curtailed, delayed or canceled as a result of a variety of factors, including but not limited to:

•: unexpected drilling conditions;
•: title and permitting problems;
•: pressure or irregularities in formations;
•: equipment failures or accidents;
•: volatility in crude oil and natural gas prices;
•: adverse weather conditions; and
•: increases in the costs of, or shortages or delays in the availability of, chemicals, drilling rigs and equipment.

Certain of our current development and exploration (waterflood or EOR techniques where no proved waterflood or EOR reserves have previously been recorded) activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all crude oil and natural gas activities, whether developmental or exploratory, involve these risks, exploratory activities involve greater risks of failure to find and produce commercial quantities of crude oil or natural gas.

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

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

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

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

Table of Contents

We are subject to many restrictions under our credit agreements which may adversely impact our future operations.

We may depend on our credit agreements for future capital needs. As required by our credit agreements, we have pledged substantially all of our oil and natural gas properties as collateral to secure the payment of our indebtedness. The credit agreements have certain restrictions on our ability to obtain additional financing, make investments, sell assets, grant liens, repurchase, redeem or retire our securities, enter into specific transactions with our subsidiaries or affiliates and engage in business combinations. Our credit agreements prohibit us from declaring or paying dividends on our common stock. We are also required to comply with certain financial covenants and ratios.

These financial covenants and ratios could limit our ability to obtain future financing, make needed capital expenditures, withstand a downturn in our business or the economy in general, including the current downturn in the economy, or otherwise conduct necessary corporate activities. Although we are currently in compliance with these covenants, in the past we have had to request waivers from or enter into amendments with our lenders to avoid default because of our anticipated non-compliance with certain financial covenants and ratios. Any future default, if not cured or waived, could result in the acceleration of all indebtedness outstanding under our credit agreements. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it, which could force us to sell significant assets or to have our assets foreclosed upon which could have a material adverse effect on our business or financial results. Even if new financing were available in light of the current credit market, it may not be on terms that are acceptable to us.

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 Senior and/or the Subordinated Credit Agreements as of December 31, 2009. We are currently in discussions with our lenders regarding this possibility and potential remedies, 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.

In addition, our Senior Credit Agreement limits the amounts we can borrow to a borrowing base amount, determined solely by the lenders, based upon projected cash flows from the oil and natural gas properties securing our loan. The lenders can independently adjust the borrowing base and the borrowings permitted to be outstanding under our Senior Credit Agreement.

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

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

Table of Contents

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

The year ended June 30, 2007 was the first year that we were subject to Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent auditors addressing our internal controls and management's assessment. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, we may be in violation of our lending covenants, investors could lose confidence in our reported financial information and the price of our stock could decrease as a result.

During our evaluation of disclosure controls and procedures for the year ended June 30, 2009, we concluded that we maintained effective internal control over financial reporting as of June 30, 2009, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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

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

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

•: fires;
•: natural disasters;
•: explosions;
•: pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;
•: weather;
•: failure of oilfield drilling and service tools;
•: changes in underground pressure in a formation that causes the surface to collapse or crater;
•: pipeline ruptures or cement failures;
•: environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and
•: availability of needed equipment at acceptable prices, including steel tubular products.

Any of these risks can cause substantial losses resulting from:

•: injury or loss of life;
•: damage to and destruction of property, natural resources and equipment;
•: pollution and other environmental damage;
•: regulatory investigations and penalties;
•: suspension of our operations; and
•: repair and remediation costs.

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance policies currently provide for $1,000,000 general liability coverage for bodily injury and property damage

Table of Contents

including pollution, underground resources, blow-out and cratering. In addition, we have $1,000,000 coverage for our contractual obligations to our service contractors using their equipment downhole if it is damaged as a result of a blow-out. We have "an "Owned-Hired and Non-Owned" Commercial Automobile liability limit of $1,000,000. We also have secured $50,000,000 umbrella coverage in excess of the general liability and automobile liability. There is a $2,000,000 policy for control of well, redrill, and pollution on drilling wells and a $1,000,000 policy for control of well, redrill and pollution on producing wells. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.

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

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

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

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

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

•: our common stock is suspended from trading or fails to be listed on the AMEX, the New York Stock Exchange, the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market;
•: we fail to convert and do not cure this failure within 10 business days after the conversion date or give notice of our intention not to comply with a request for conversion;
•: we fail to pay for at least 5 business days any amount when due pursuant to the terms of the Preferred Stock or any documents related to the sale and registration rights of the Preferred Stock, common stock and warrants;
•: we take certain actions, or third parties take certain actions, with regard to bankruptcy;
•: we default on any indebtedness which default is not waived and the applicable grace period has expired; or
•: we breach any representation, warranty, covenant or other term or condition of any document relating to the sale and registration rights relating to the Preferred Stock, the common stock and the warrants, which, to the extent such breach is curable, such breach is not cured within 7 business days.

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

Table of Contents

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

We are subject to a lawsuit relating to a fire that occurred on March 12, 2006 in Carson County, Texas which may have an adverse impact on us.

Cano and certain of its subsidiaries were defendants in several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas and remain defendants in one of the lawsuits. With regard to the one remaining lawsuit, on June 21, 2007, the judge of the 100th Judicial District Court issued a Final Judgment (a) granting motions for summary judgment in favor of Cano and certain of its subsidiaries on plaintiffs' claims for (i) breach of contract/termination of an oil and gas lease and (ii) negligence; and (b) granting the plaintiffs' no-evidence motion for summary judgment on contributory negligence, assumption of risk, repudiation and estoppel affirmative defenses asserted by Cano and certain of its subsidiaries.

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

The remaining plaintiff alleges damages to land and livestock, certain expenses related to fighting the fire and remedial expenses totaling approximately $1.7 million to $1.8 million. In addition the remaining plaintiff seeks termination of certain oil and natural gas leases, reimbursement of their attorneys' fees and exemplary damages. Currently, known aggregate actual damage claims are approximately $1.8 million. However, the plaintiff has not provided actual damage claims for all of their claims. These actual damage claims do not include the additional claims by the plaintiffs for attorneys' fees and exemplary damages, the potential amounts of which cannot be reasonably estimated. There is no remaining insurance coverage for the fire litigation. We may not prevail in court or on further appeal or be able to settle the remaining lawsuit on acceptable terms. If there is an adverse judgment entered against us, based on the illiquid nature of a significant portion of our assets, we may not be able to (i) post a sufficient supersedeas bond during the appeal process of any adverse judgment, which may permit the plaintiffs to attempt to execute on any judgment pending appeal, and/or (ii) satisfy the amount of any adverse judgment.

Currently, our lease operating expense per BOE is high in comparison to the oil and natural gas industry as a whole.

Until such time as we achieve significant production growth from our waterfloods, our lease operating expense per BOE should remain higher than companies drilling for primary production. Our current net production of approximately 1,300 BOEPD is produced from our 1,924 wells. These higher operating costs could have an adverse effect on our results of operations.

Table of Contents

Risks Related to Our Common Stock

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

The public market for our common stock has historically been very volatile. Since we acquired Davenport Field Unit on May 28, 2004 and through the fiscal year ended June 30, 2009, the market price for our common stock has ranged from $0.22 to $10.65. On September 22, 2009, our closing price on the NYSE Amex was $1.08. Any future market price for our shares may continue to be very volatile. The stock market in general has experienced extreme price and volume fluctuations that often are unrelated or disproportionate to the operating performance of companies. Broad market factors and the investing public's negative perception of our business may reduce our stock price, regardless of our operating performance. Market fluctuations and volatility, as well as general economic, market and political conditions, could reduce our stock price. As a result, this may make it difficult or impossible for you to sell our common stock for a positive return on your investment.

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

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

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

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

•: that a broker or dealer approve a person's account for transactions in penny stocks; and
•: the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

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

•: obtain financial information and other information regarding the investment experience and objectives of the person; and
•: make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

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

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

Table of Contents

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

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

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

The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control the reports these analysts publish about us. Furthermore, there are many large, well-established, publicly-traded companies active in our industry and market, which may make it less likely that we will receive widespread analyst coverage. If one or more of the analysts who do cover us downgraded our stock, our stock price would likely decline rapidly. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.

We do not pay dividends on our common stock.

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

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

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

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

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

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

Table of Contents

•: dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;
•: dilution of the equity interest of common stock and other series of preferred stock; and
•: limitation on the right of holders of common stock and other series of preferred stock to share in Cano's assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.

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

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

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

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

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

•: to modify the certificate of incorporation or bylaws in a manner adverse to the Preferred Stock;
•: increase or decrease the number of authorized shares of Preferred Stock;
•: create any class of preferred stock that has a preference over or is in parity with the Preferred Stock with respect to dividends or liquidation;
•: purchase, repurchase or redeem any share of common stock;
•: pay dividends or make any other distribution on the common stock; or
•: circumvent a right of the Preferred Stock.

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

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

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

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

Table of Contents

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

See "Items 1 and 2. Business and Properties."

Item 3. Legal Proceedings.

Burnett Case

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

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. We have not yet determined whether to seek further review by the Court of Appeals or the Texas Supreme Court. Based on our knowledge and judgment of the facts as of June 30, 2009, we believe our financial statements present fairly the effect of actual and anticipated ultimate costs to resolve these matters as of June 30, 2009.

Table of Contents

Settled Cases

On April 28, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. (the "Adcock case"). The plaintiffs claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) alleged negligence, res ipsa loquitor, trespass and nuisance and (ii) sought damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $5,439,958. In addition, the plaintiffs sought (i) reimbursement for their attorneys' fees and (ii) exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The claims of all plaintiffs in this suit were resolved through a Settlement and Release Agreement effective November 5, 2008 and were dismissed with prejudice.

On July 6, 2006, Anna McMordie Henry and Joni McMordie Middleton intervened in the Adcock case. The intervenors (i) alleged negligence and (ii) sought damages totaling $64,357 as well as exemplary damages. The claims of these intervenors were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On July 20, 2006, Abraham Brothers, LP, Edward C. Abraham, Salem A. and Ruth Ann Abraham and Jason M. Abraham intervened in the Adcock case. The intervenors (i) alleged negligence, nuisance, and trespass and (ii) sought damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $3,252,862. In addition, the intervenors sought (i) reimbursement for their attorneys' fees and (ii) exemplary damages. The intervenors also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The claims of Abraham Brothers, LP, Edward C. Abraham, Salem A. and Ruth Ann Abraham and Jason M. Abraham (along with those asserted by Abraham Equine, Inc. discussed below) were resolved through a Settlement Agreement and Release effective October 12, 2008 and were dismissed with prejudice.

On August 9, 2006, Riley Middleton intervened in the Adcock case. The intervenor (i) alleged negligence and (ii) sought damages totaling $233,386 as well as exemplary damages. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On April 10, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas, Cause No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc. (the "Hutchinson case"). The plaintiffs claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) alleged negligence and trespass and (ii) sought damages of $621,058, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs sought exemplary damages. The claims of all plaintiffs were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On May 1, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1923, Chisum Family Partnership, Ltd. v. Cano, W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. (the "Chisum case"). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleged negligence and trespass and (ii) sought damages of $53,738.82, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs sought exemplary

Table of Contents

damages. The claims of all plaintiffs and intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On August 9, 2006, the following lawsuit was filed in the 233rd Judicial District Court of Gray County, Texas, Cause No. 34,423, Yolanda Villarreal, Individually and on behalf of the Estate of Gerardo Villarreal v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd., and WO Energy, Inc. (the "Villarreal case"). The plaintiffs claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) alleged negligence and (ii) sought damages for past and future financial support in the amount of $586,334, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages, for the wrongful death of Gerardo Villarreal who they claimed died as a result of the fire. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable under vicarious liability theories. On August 22, 2006, relatives of Roberto Chavira intervened in the case alleging similar claims and sought damages for lost economic support and lost household services in the amount of $894,078, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages regarding the death of Roberto Chavira. The claims of all plaintiffs and intervenors were resolved through Settlement and Release Agreements effective December 8, 2008 and were dismissed with prejudice.

On March 14, 2007, the following lawsuit was filed in 100th Judicial District Court in Carson County, Texas; Cause No. 9994, Southwestern Public Service Company d/b/a Xcel Energy v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc. (the "SPS case"). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleged negligence and breach of contract and (ii) sought $1,876,000 in damages for loss and damage to transmission and distribution equipment, utility poles, lines and other equipment. In addition, the plaintiff sought reimbursement of its attorney's fees. The claims of plaintiff were resolved through a Settlement and Release Agreement effective January 8, 2009 and were dismissed with prejudice.

On May 2, 2007, the following lawsuit was filed in the 84th Judicial District Court of Hutchinson County, Texas, Cause No. 37,619, Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Burgess case"). Eleven plaintiffs claimed that electrical wiring and equipment relating to oil and gas operations of the Company or certain of its subsidiaries started a wildfire that began on March 12, 2006 in Carson County, Texas. Five of the plaintiffs were former plaintiffs in the Adcock matter. The plaintiffs (i) alleged negligence, res ipsa loquitor, nuisance, and trespass and (ii) sought damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $1,997,217.86. In addition, the plaintiffs sought (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of all plaintiffs were resolved through a Settlement and Release Agreement effective November 5, 2008 and were dismissed with prejudice.

On May 15, 2007, William L. Arrington, William M. Arrington and Mark and Le'Ann Mitchell intervened in the SPS case. The intervenors (i) alleged negligence, res ipsa loquitor, nuisance, and trespass and (ii) sought damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $118,320. In addition, the intervenors sought (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The claims of these intervenors were resolved

Table of Contents

through a Settlement and Release Agreement effective November 5, 2008 and were dismissed with prejudice.

On September 25, 2007, the Texas Judicial Panel on Multidistrict Litigation granted Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc.'s Motion to Transfer Related Cases to Pretrial Court pursuant to Texas Rule of Judicial Administration 13. The panel transferred all pending cases (Adcock, Chisum, Hutchison, Villarreal, SPS, and Burgess, identified above, and Valenzuela, Abraham Equine, Pfeffer, and Ayers, identified below) that assert claims against the Company and its subsidiaries related to wildfires beginning on March 12, 2006 to a single pretrial court for consideration of pretrial matters. The panel transferred all then-pending cases to the Honorable Paul Davis, retired judge of the 200th District Court of Travis County, Texas, as Cause No. D-1-GN-07-003353.

On October 3, 2007, Firstbank Southwest, as Trustee for the John and Eddalee Haggard Trust (the "Trust") filed a Petition in intervention as part of the Hutchison case. The Trust claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The Trust (i) alleged negligence and trespass and (ii) sought damages of $46,362.50, including, but not limited to, damages to land and certain remedial expenses. In addition, the Trust sought exemplary damages. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On January 10, 2008, Philip L. Fletcher intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleged negligence, trespass and nuisance and (ii) sought damages of $120,408, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On January 15, 2008, the Jones and McMordie Ranch Partnership intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleged negligence, trespass and nuisance and (ii) sought damages of $86,250.71, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On February 11, 2008, the following lawsuit was filed in the 48th Judicial District Court of Tarrant County, Texas: Cause No. 048-228763-08, Abraham Equine, Inc. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Abraham Equine case"). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleged negligence, trespass and nuisance and (ii) sought damages of $1,608,000, including, but not limited to, damages to its land, livestock and lost profits. In addition, the plaintiff sought (i) reimbursement for its attorney's fees and (ii) exemplary damages. The plaintiff also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. This suit (along with the claims of Abraham Brothers, LP, Edward C. Abraham, Salem A.

Table of Contents

and Ruth Ann Abraham and Jason M. Abraham, discussed above) was resolved through a Settlement and Release Agreement effective October 12, 2008 and were dismissed with prejudice.

On March 10, 2008, the following lawsuit was filed in the 352nd Judicial District Court of Tarrant County, Texas, Cause No. 352-229256-08, Gary Pfeffer v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Pfeffer case"). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleged negligence, trespass and nuisance, (ii) sought undisclosed damages for the wrongful death of his father, Bill W. Pfeffer, who he claimed died as a result of the fire and (iii) sought actual damages of $1,023,572.37 for damages to his parents' home and property. In addition, the plaintiff sought exemplary damages. The plaintiff also claimed that Cano and its subsidiaries were jointly and severally liable as a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. The claims of plaintiff were resolved through a Settlement and Release Agreement effective December 10, 2008 and were dismissed with prejudice.

On March 11, 2008, the following lawsuit was filed in the 141st Judicial District Court of Tarrant County, Texas, Cause No. 141-229281-08, Pamela Ayers, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Ayers case"). The plaintiffs claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) alleged negligence and (ii) sought undisclosed damages for the wrongful death of their mother, Kathy Ryan, who they claimed died as a result of the fire. In addition, the plaintiffs sought exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. The claims of plaintiffs were resolved through a Settlement and Release Agreement effective December 10, 2008 and were dismissed with prejudice.

On March 12, 2008, the following lawsuit was filed in the 17th Judicial District Court of Tarrant County, Texas, Cause No. 017-229316-08, The Travelers Lloyds Insurance Company and Travelers Lloyds of Texas Insurance Company v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Travelers case"). The plaintiffs claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) alleged negligence, res ipsa loquitor, and trespass and (ii) claimed they are subrogated to the rights of their insureds for damages to their buildings and building contents totaling $447,764.60. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership. The claims of plaintiffs were resolved through a Settlement and Release Agreement effective November 18, 2008 and were dismissed with prejudice.

Table of Contents

wrongful death of four relatives, Manuel Dominguez, Roberto Chavira, Gerardo Villarreal and Medardo Garcia, who they claimed died as a result of the fire. In addition, plaintiffs sought (i) reimbursement for their attorneys' fees and (ii) exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. The claims of plaintiffs were resolved through a Settlement and Release Agreement effective April 9, 2009 and were dismissed with prejudice.

Insurance and Other Settlements Related to the Fire Litigation

On June 20, 2006, the following lawsuit was filed in the United States District Court for the Northern District of Texas, Fort Worth Division, C.A. No. 4-06cv-434-A, Mid-Continent Casualty Company ("Mid-Con") v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and W.O. Energy, Inc. seeking a declaration that the plaintiff is not responsible for pre-tender defense costs and that the plaintiff has the sole and exclusive right to select defense counsel and to defend, investigate, negotiate and settle the litigation described above. On September 18, 2006, the First Amended Complaint for Declaratory Judgment was filed with regard to the cases described above.

On February 9, 2007, Cano and its subsidiaries entered into a Settlement Agreement and Release with Mid-Con pursuant to which in exchange for mutual releases, in addition to the approximately $923,000 that we have been reimbursed by Mid-Con, Mid-Con agreed to pay Cano within 20 business days of February 9, 2007 the amount of $6,699,827 comprising the following: (a) the $1,000,000 policy limits of the primary policy; (b) the $5,000,000 policy limits of the excess policy; (c) $500,000 for future defense costs; (d) $144,000 as partial payment for certain unpaid invoices for litigation related expenses; (e) all approved reasonable and necessary litigation related expenses through December 21, 2006 that are not part of the above-referenced $144,000; and (f) certain specified attorneys fees. During February 2007, we received the $6,699,827 payment from Mid-Con. Of this $6,699,827 amount, the payments for policy limits amounting to $6,000,000 were recorded as a liability under deferred litigation credit as presented on our consolidated balance sheet.

On March 11, 2008, one of Cano's subsidiaries entered into a tolling agreement with an independent electrical contractor that was identified as a potentially responsible third party in connection with the claims related to the pending wildfire litigation against Cano and its subsidiaries. In accordance with the terms of a Settlement and Release Agreement effective October 11, 2008, the independent electrical contractor paid Cano its full insurance policy limits totaling $6.0 million in exchange for a full release of any existing or future claims related to wildfires that began on March 12, 2006 in Carson County, Texas. The $6.0 million was received on October 31, 2008.

The $12.0 million of insurance proceeds (from Mid-Con and the independent electrical contractor) have been expended directly or indirectly to pay the settlements described above. Accordingly, we no longer have a deferred litigation credit balance. During the year ended June 30, 2009, we incurred expense of $6.6 million for legal and settlement expenses in connection with the fire litigation lawsuits.

Table of Contents

returned to us 434,783 shares of Cano common stock owned by the W.O. Sellers which had been held in trust for our benefit. The shares are held by us as treasury stock. In addition, the W.O. Sellers provided additional consideration (collectively, the 434,783 shares and the additional consideration being the "W.O. Settlement").

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 (the "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.

Environmental

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

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

No matters were submitted to a vote of security holders during the quarter ended June 30, 2009.

Table of Contents

PART II

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

Market Information

Our shares of common stock are listed on the NYSE Amex under the trading symbol "CFW." For the years ended June 30, 2008 and 2009, the following table sets forth the high and low sales prices per share of common stock for each quarterly period. On September 24, 2009, the closing sale price on the NYSE Amex was $0.99.

	Fiscal 2009				Fiscal 2008

	High		Low		High		Low
Fiscal Quarter
First Quarter Ended September 30	$	8.03	$	2.01	$	7.42	$	5.05
Second Quarter Ended December 31	$	2.34	$	0.22	$	8.85	$	5.94
Third Quarter Ended March 31	$	0.75	$	0.24	$	7.50	$	3.85
Fourth Quarter Ended June 30	$	1.55	$	0.40	$	9.40	$	4.29

Holders

As of September 25, 2009, our shares of common stock were held by approximately 112 stockholders of record. In many instances, a record stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares. We estimate that, as of September 25, 2009, there were approximately 4,000 beneficial holders who own shares of our common stock in street name.

Dividends

We have not declared any dividends to date on our common stock. We have no present intention of paying any cash dividends on our common stock in the foreseeable future, as we intend to use earnings, if any, to generate growth. Our credit agreements do not permit us to pay dividends on our common stock. In addition, the terms of our Preferred Stock do not permit us to pay dividends on our common stock without the approval of the holders of a majority of the Preferred Stock.

For the year ended June 30, 2009, the Preferred Stock dividend was $2.7 million, of which $1.6 million pertained to holders of the pay-in-kind ("PIK") dividend option.

Except as set forth below, during the year ended June 30, 2009, there were no equity securities issued pursuant to transactions exempt from the registration requirements under the Securities Act of 1933, as amended, that were not disclosed previously in Current Reports on Form 8-K or Quarterly Reports on Form 10-Q.

Table of Contents

ISSUER PURCHASES OF EQUITY SECURITIES

Period		Average Price Paid per Share (or Unit)

April 1, 2009 through April 30, 2009	—		—	—	—
May 1, 2009 through May 31, 2009	32,150	$	0.82	—	—
June 1, 2009 through June 30, 2009	16,752	$	0.86	—	—
Total	48,902	$	0.83	—	—

(1): These shares of our common stock were delivered to us during the fourth quarter of 2009 to satisfy tax withholding obligations by S. Jeffrey Johnson, Benjamin Daitch, Patrick McKinney, Michael J. Ricketts and Phillip Feiner pursuant to the terms of the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan to satisfy tax withholding obligations related to the vesting of their respective restricted stock awards.

Performance Graph

The following performance graph compares the cumulative total stockholder return on our common stock with the Standard & Poor's 500 Stock Index (the "S&P 500") and the S&P Supercomposite Oil & Gas Exploration & Production Index for the period from June 4, 2004 to June 30, 2009, assuming an initial investment of $100 and the reinvestment of all dividends, if any.

Table of Contents

Item 6. Selected Financial Data.

The following selected financial information (which is not covered by the report of an independent registered public accounting firm) is summarized from our results of operations for the five-year period ended June 30, 2009 and should be read in conjunction with the consolidated financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data."

		Years Ended June 30,

In Thousands, Except Per Share Data		2009			2008			2007			2006			2005
Operating Revenues:
Total operating revenues		$	25,409		$	34,650		$	20,651		$	14,371		$	3,764
Operating Expenses:
Lease operating			18,842			13,273			8,733			5,952			2,069
Production and ad valorem taxes			2,352			2,454			1,695			985			223
General and administrative			19,156			14,859			12,635			7,623			4,754
Impairment of long-lived assets			26,670			—			—			—			—
Exploration expense			11,379			—			—			—			—
Depletion and depreciation			5,720			3,903			3,202			1,652			371
Accretion of discount on asset retirement obligations			305			204			131			89			48

	Total operating expenses		84,424			34,693			26,396			16,301			7,465

Loss from operations:			(59,015	)		(43	)		(5,745	)		(1,930	)		(3,701	)

Other income (expense):
Gain (loss) on derivatives			43,790			(31,955	)		(847	)		(2,705	)		—
Impairment of goodwill			(685	)		—			—			—			—
Interest expense and other			(513	)		(761	)		(1,681	)		(2,075	)		12

	Total other income (expense)		42,592			(32,716	)		(2,528	)		(4,780	)		12
Loss from continuing operations before income tax benefit			(16,423	)		(32,759	)		(8,273	)		(6,710	)		(3,689	)
Deferred income tax benefit			4,712			11,767			2,970			3,990			—

Loss from continuing operations			(11,711	)		(20,992	)		(5,303	)		(2,720	)		(3,689	)
Income from discontinued operations, net of related taxes			11,480			3,471			4,513			876			716
Preferred stock discount			—			—			—			—			417
Preferred stock dividend			(2,730	)		(4,083	)		(3,169	)		—			—
Preferred stock repurchased for less than carrying amount			10,890			—			—			—			—

Net income (loss) applicable to common stock		$	7,929		$	(21,604	)	$	(3,959	)	$	(1,844	)	$	(3,390	)

Net income (loss) applicable to common stock:
	Continuing operations		(3,551	)		(25,075	)		(8,472	)		(2,720	)		(4,106	)
	Discontinued operations		11,480			3,471			4,513			876			716

	Net income (loss) applicable to common stock	$	7,929		$	(21,604	)	$	(3,959	)	$	(1,844	)	$	(3,390	)

Net income (loss) per share—basic and diluted		$	0.17		$	(0.60	)	$	(0.13	)	$	(0.08	)	$	(0.29	)

Weighted average common shares outstanding
	Basic and diluted		45,361			35,829			30,758			22,364			11,839

Table of Contents

	As of June 30,

	2009			2008			2007			2006			2005
CASH FLOW DATA:
Cash flow provided by (used in):
Operating activities	$	(6,609	)	$	17,028		$	2,658		$	(6,083	)	$	(501	)
Investing activities		(17,349	)		(84,751	)		(39,854	)		(78,365	)		(10,726	)
Financing activities		23,653			66,301			38,670			84,948			9,797
BALANCE SHEET DATA:
Cash and cash equivalents	$	392		$	697		$	2,119		$	645		$	145
Total assets		264,028			277,734			201,469			146,949			17,578
Long-term debt		55,700			73,500			33,500			68,750			—
Temporary equity		25,405			45,086			47,596			—			—
Stockholders' equity		148,459			83,850			68,861			40,636			15,391

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

Overview

Introduction

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

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

Table of Contents

We believe our portfolio of crude oil and natural gas properties provides opportunities to apply our operational strategy. Additionally, we will continue to evaluate acquisitions that are consistent with our operational strategy.

Overall estimated proved oil and natural gas reserves decreased by 4.1 MMBOE, or 7.7%, to 49.1 MMBOE as of June 30, 2009, as compared to 53.2 MMBOE as of June 30, 2008. 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. Additional detail of our proved reserves is presented in "Items 1 and 2 Business and Properties—Proved Reserves."

At our Cato Properties, we added approximately 2,623 MBOE of new reserves in extensions and discoveries due to better than expected initial waterflood response in the Phase I area of the project. Cato's production increased from roughly 200 BOEPD to over 400 BOEPD as injection into the waterflood pattern commenced in the 19 injection wells and direct crude oil production increases occurred in 29 pattern producing wells. Ultimately, this led to the conversion of approximately 1,181 MBOE of PUD to PDP reserves. Approximately 724 MBOE of prior year PUD to PDP reserve conversions at our Panhandle Properties waterflood were reclassified back to PUD based upon actual response realized through June 30, 2009 (which has been slower than originally estimated). Offsetting the positive extensions and discoveries at our Cato Properties (2,623 MBOE) were the divestitures of our Corsicana and Pantwist Properties, as discussed in Note 8 to our Consolidated Financial Statements, totaling 2,554 MBOE, the impairment of 2,269 MBOE at our Desdemona Barnett Shale Properties due to the decline in commodity prices during the year ended June 30, 2009 (the "2009 Fiscal Year"), as discussed in Note 14 to our Consolidated Financial Statements, and other revisions primarily driven by the decline in commodity prices and forecast changes which changed the estimated economic lives of our assets (1,435 MBOE). A summary of the year-on-year changes to our proved reserves is shown in the following table:

Summary of Changes in Proved Reserves

Reserves at June 30, 2008	53,189
Extensions and Discoveries	2,623
Forecast Revisions	(1,435	)
Financial Revisions (impairment)	(2,269	)
Sales of Assets	(2,554	)
Production	(457	)

Reserves at June 30, 2009	49,097

Drilling Capital Development and Operating Activities Update

For the 2009 Fiscal Year, we incurred $52.6 million of capital expenditures ($56.2 million spent) to develop our existing fields. The $3.6 million difference between the $52.6 million incurred and the $56.2 million spent is primarily timing differences related to expenditures incurred during the 2008 Fiscal Year and the payments for those capital expenditures during the 2008 Fiscal Year. At June 30, 2009, we had accrued capital expenditures of $1.9 million that were paid during the 2010 Fiscal Year.

The goal for the 2009 Fiscal Year was to convert existing PUD reserves to PDP reserves and increase production. The company drilled and completed 18 wells: four ASP observation wells at the Nowata Field, five wells in the Panhandle Field (four Harvey Unit waterflood development wells and

Table of Contents

one Cockrell ranch infill well), and nine wells at Cato (six waterflood producers and three waterflood injectors).

For the year ending June 30, 2010 (the "2010 Fiscal Year"), our Board of Directors has approved a capital development budget of $13.9 million as follows:

•: $5.4 million at the Cato Properties;
•: $7.8 million at the Panhandle Properties; and
•: $0.7 million at the remaining Properties.

Our 2010 Fiscal Year capital development program does not include the drilling of new wells. The financing of our capital expenditures is discussed below under "Liquidity and Capital Resources." The following reviews our capital development activity during the 2009 Fiscal Year and planned activity during the 2010 Fiscal Year.

Cato Properties. Proved reserves as of June 30, 2009 attributable to the Cato Properties were 16.0 MMBOE, of which 1.9 MMBOE were PDP, 0.5 MMBOE were PDNP and 13.6 MMBOE were PUD. These properties include roughly 20,000 acres across three fields in Chavez and Roosevelt Counties, New Mexico. The prime asset is the roughly 15,000 acre Cato Field, which produces from the historically prolific San Andres formation, which has been successfully waterflooded in the Permian Basin for over 30 years. There were two successful waterflood pilots conducted in the field in the 1970's by Shell and Amoco.

We have experienced encouraging initial waterflood response at the Cato Field. The first phase of development (Phase I) includes 19 water injection wells ("injectors") and 29 producing wells ("producers"). Once the injection permits were received in September 2008, we began injecting 7,000 barrels of water per day ("BWIPD"). As we continued injecting water into the field, waterflood production has grown from five producers during December 2008 offsetting a prior Amoco waterflood pilot to 29 producers experiencing production as of June 30, 2009. During January 2009, we increased the injection rate to approximately 12,000 BWIPD. During February 2009, we expanded the footprint of Phase 1 of the Cato waterflood from 550 to roughly 640 acres and announced an increased capital expenditures budget to $49.8 million, of which $27.0 million was intended for the Cato Properties. We currently have ten sub-pumps operating in the field and plan to install additional sub-pumps to support increasing production and corresponding higher levels of fluid production. The sustained production gains at the Cato Properties are the result of an earlier than expected waterflood production response.

The 2009 Fiscal Year drilling program at Cato, which comprised drilling nine wells (six waterflood producers and three waterflood injectors), was completed in October 2008. Normal production declines were experienced outside of the Phase I waterflooded area, but these declines were more than offset by increased production from the waterflood.

At June 30, 2009, we booked proved reserves extensions and discoveries at Cato as Phase I results were better than initially expected. Field production increased from roughly 200 BOEPD to over 400 BOEPD after we commenced injection into 19 injection wells of the waterflood pattern which led to increased crude oil production in 29 producers. When we increased the waterflood footprint from 550 acres to 640 acres, the rate of water injection per acre decreased leading to a temporary decrease in production. We added approximately 2.6 MMBOE of new reserves based on the responses experienced through June 30, 2009. Additionally, 1.1 MMBOE of PUD reserves were reclassified to PDP reserves as a result of the responses experienced in Phase I. We plan to increase the number of injection wells and enlarge the waterflood footprint in the 2010 Fiscal Year. Net production at Cato averaged 316 BOEPD in June 2009.

Panhandle Properties. Proved reserves as of June 30, 2009 attributable to the Panhandle Properties were 28.9 MMBOE, of which 3.5 MMBOE were PDP and 25.4 MMBOE were PUD. These

Table of Contents

properties include roughly 20,000 acres in Carson, Gray and Hutchinson Counties, Texas. They are delineated in thirty-three leases—the largest of which are Cockrell Ranch, Pond, Harvey, Mobil Fee, Cooper, Block and Schafer Ranch.

During the quarter ended June 30, 2009, we maintained our average daily water injection rate at the Cockrell Ranch Unit (our first Panhandle Properties waterflood) at roughly 75,000 barrels per day. This resulted in increasing our average daily production at the Cockrell Ranch Unit from approximately 80-100 net BOEPD between June and December 2008 to maintaining 100-120 net BOEPD production through June 30, 2009. While crude oil production continues to increase at Cockrell Ranch, the gains are below our expectations. Based on actual performance of the waterflood through June 30, 2009, we reclassified 724 MBOE of PDP reserves back to PUD at June 30, 2009. After this reclassification, the remaining amount of the prior year conversion of PUD to PDP reserves is 674 MBOE. We have retained Netherland, Sewell & Associates, Inc. to assist us with reservoir analysis and simulation work at Cockrell Ranch. We are establishing a controlled injection pattern to gauge the effects of optimizing water injection into the highest remaining crude oil saturation intervals of the Brown Dolomite formation (our target producing formation). The result of this field observation, coupled with rigorous reservoir simulation modeling, should allow us to move the project forward into a more predicable production response profile. Moreover, the analysis will improve our planning of future capital development programs for the remaining Panhandle Properties leases. Waterflood production will be curtailed from the previously reported 100-120 BOEPD to 60-80 BOEPD during the test period. As of the end of September 2009, all previously curtailed production will have been restored.

Our original 2009 Fiscal Year waterflood capital development plan for the Panhandle Properties included six separate mini-floods on reduced well spacing to enable us to accelerate field development. Tighter well-spacing and smaller development patterns should accelerate permitting and response times, allowing a larger development footprint over a greater acreage position. The amended 2009 capital development plan provided for the development of only one mini-flood phase through June 2009 (the Harvey Unit). The Harvey Unit had its waterflood permit application approved by the Texas Railroad Commission on October 20, 2008. The Harvey Unit mini-flood consists of six injection wells and 13 producing wells (which required four new wells to be drilled among the existing wells at the field). The drilling of the four replacement injector wells was completed on January 5, 2009, thus completing the mini-flood pattern. We initiated injection at the Harvey Unit on March 30, 2009 at a rate of 2,500 barrels per day. During the 2009 Fiscal Year, we received approval of the mini-flood permits at the Pond Lease and at the Olive-Cooper Lease. As a result of the reduction in our capital plan and a focus on our Cato Properties, we slowed the filing of Panhandle mini-flood permits. We now expect to file the appropriate waterflood permits for the remaining three mini-floods by the quarter ending December 31, 2009. Net production at the Panhandle Properties for June 2009 was 627 BOEPD.

Desdemona Properties. Proved reserves as of June 30, 2009 attributable to the Desdemona Properties were 1.4 MMBOE, of which 0.1 MMBOE were PDP and 1.3 MMBOE were PDNP. Approximately 1.3 MMBOE of the reserves were attributable to the Duke Sand reservoir.

Desdemona Properties—Waterflood. We drilled and completed 11 required replacement wells to initiate the development of the Duke Sand Waterflood on the Desdemona Properties during the 2008 Fiscal Year having procured and completed infrastructure of the waterflood facilities in September 2007. Water injection commenced in September 2007. Through June 30, 2009, we have injected over 1.5 million barrels of water into a pilot location of the Duke Sand reservoir. The primary source of water for the waterflood was from our Barnett Shale natural gas wells. During July 2009, we shut-in our remaining Barnett Shale producing wells due to continued low natural gas prices. Accordingly, the source for water injection for our Duke Sand waterflood pilot ceased. Without a known economic source of water, we will not continue to defer expenditures associated with this waterflood. Therefore, we expensed $11.4 million during June 2009 for the aggregate deferred expenditures spent to implement this waterflood pilot, as discussed

Table of Contents

in Note 9 to our Consolidated Financial Statements. We continue to believe that this reservoir is an excellent secondary and tertiary recovery candidate; however, we do not have current plans to recommence injection for the foreseeable future. We had no proved reserves for the Duke Sand Waterflood pilot project.

Desdemona Properties—Barnett Shale. We drilled and completed 15 vertical and 8 horizontal wells in the Barnett Shale during the 2007 and 2008 Fiscal Years. Due to the decline in natural gas commodity prices and based upon operating performance, there was uncertainty in the likelihood of developing PUDs associated with our Barnett Shale Properties. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties and a $0.7 million pre-tax impairment to the goodwill associated with our subsidiary which holds the equity in our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline, as discussed in Note 9 to our Consolidated Financial Statements. During July 2009, we shut-in our Barnett Shale natural gas wells, and, based upon the current and near-term outlook of natural gas prices, we have no plans to return these wells to production in the foreseeable future.

Net production for June 2009 at the Desdemona Properties was 54 BOEPD. Based upon the previously discussed shut-in wells, the production rates are estimated to be 30-35 BOEPD for the foreseeable future.

Nowata Properties. Proved reserves as of June 30, 2009 attributable to the Nowata Properties were 1.5 MMBOE, all of which were PDP. Our ASP tertiary recovery pilot project has been in full operation since December 2007. Through June 30, 2009, we have injected approximately .40 PVI of ASP and polymer flush. We drilled and completed four observation wells in December 2008, to enable us to test flood-front results in the pilot project. We completed injecting of our Polymer flush during June 2009. We anticipate completing the full ASP Pilot performance analysis within the next three to six months, and we estimate additional completion costs to total $0.3 million. There are currently no proved reserves associated with the ASP Pilot. Net production for June 2009 at the Nowata Properties was 229 BOEPD.

Davenport Properties. Proved reserves as of June 30, 2009 attributable to the Davenport Properties were 1.3 MMBOE, of which 0.7 MMBOE were PDP and 0.6 MMBOE were PDNP. Net production at the Davenport Properties for June 2009 was 79 BOEPD.

Industry Conditions

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

We do believe significant acquisition opportunities exist and will continue to exist as major energy companies and larger independents continue to focus their attention and resources toward the discovery and development of large fields and smaller companies are faced with decreasing margins and access to capital.

Table of Contents

Our Strategy

•: Exploit and Develop Existing Properties. We believe we have an attractive portfolio of assets to implement our business plan. We intend to add proved reserves to, and increase production from, our existing properties through the application of commonly used EOR technologies, including water, gas and chemical flooding and other techniques.
•: Acquire Strategic Assets. We seek to acquire low-cost assets with reserves suitable for EOR techniques in the onshore U.S. We will continue to target acquisitions that meet our engineering and operational standards in a financially prudent manner.
•: Drill Known Formations. Our portfolio is composed of mature fields with proved primary and/or secondary reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on wildcat exploration drilling of new formations and the high degree of speculation associated with making new discoveries, but the application of commonly used secondary and/or tertiary recovery methods to increase production and reserves.

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

Liquidity and Capital Resources

Our primary sources of capital and liquidity have been issuance of securities, borrowings under our credit agreements, and cash flows from operating activities. These sources are discussed in greater detail below.

For the twelve months ended June 30, 2009, our primary sources of cash were receipts from the sale of crude oil and natural gas production, issuances of common stock, net borrowings under our credit agreements, sales of oil and gas properties, payments for in-the-money commodity derivative contracts, settlements from third parties and the W.O. Settlement pertaining to the Panhandle fire litigation as discussed in Note 17 to our Consolidated Financial Statements. Our cash receipts from sales are discussed in greater detail under "Results of Operations—Operating Revenues." The non-revenue sources of cash are discussed in greater detail below:

•: On July 1, 2008, we received net proceeds of $53.9 million from the issuance of 7.0 million shares of our common stock. The net proceeds were used to pay down long-term debt due under our senior credit agreement (See Note 4 to our Consolidated Financial Statements).
•: On October 1, 2008, we sold our wholly-owned subsidiary, Pantwist, LLC ("Pantwist"), for $42.7 million ($40.0 million net of closing adjustments of $2.1 million of discontinued operating income recorded in the first quarter of the 2009 Fiscal Year and $0.6 million in advisory fees—(See Note 8 to our Consolidated Financial Statements).
•: During October 2008, we sold certain uncovered "floor price" commodity derivative contracts covering July 2010 to December 2010 for $0.6 million to our counterparty, and during November 2008, we sold all remaining uncovered "floor price" commodity derivative contracts covering November 2008 through June 2010 for $2.6 million to our counterparty. We recorded a realized gain of $0.7 million and an unrealized gain of $1.3 million as a result of these transactions.
•: On October 31, 2008, an independent electrical contractor paid us $6.0 million (its full insurance policy limit) in exchange for a full release of any existing or future claims related to wildfires that began on March 12, 2006 in Carson County, Texas. The $6.0 million has been fully

Table of Contents

expended to cover the settlements discussed in Note 17 to our Consolidated Financial Statements.

•: On December 2, 2008, we sold our interests in the Corsicana Properties for $0.3 million (See Note 8 to our Consolidated Financial Statements).
•: On December 17, 2008, we finalized new senior and subordinated credit facilities, as discussed in Note 6 to our Consolidated Financial Statements. For the senior credit facility, the initial and current borrowing base, based upon our proved reserves, is $60.0 million and has an outstanding balance of $46.2 million as of September 28, 2009. We have fully drawn the $15.0 million borrowing under the subordinated credit facility. Our two credit facilities are discussed in greater detail below.

During the twelve month period ended June 30, 2009, our cash outlays were primarily for:

•: Lease operating expense, general and administrative expenses, and the settlement and legal fees associated with the fire litigation claims, which are discussed in greater detail in Note 17 to our Consolidated Financial Statements and under "Results of Operations—Operating Expenses."
•: Capital expenditures, which are discussed in greater detail under "Drilling Capital Development and Operating Activities Update."
•: The repurchase of 22,948 shares of Series D Convertible Preferred Stock, including accrued and unpaid PIK dividends relating to such shares for approximately $10.4 million, which is discussed in greater detail in Note 5 to our Consolidated Financial Statements.

As discussed under "Drilling Capital Development and Operating Activities," we have $52.6 million of capital expenditures during the twelve month period ended June 30, 2009. $4.8 million of the incurred $52.6 million pertains to secondary and tertiary exploration activities (new projects where no secondary or tertiary reserves have previously been recorded). As of June 30, 2009, we had implemented one tertiary exploration project that has existing reserves associated with secondary recovery activities—the ASP tertiary recovery pilot project at the Nowata Properties. This project is considered exploratory as it entails more risk compared to our development activities where proved secondary or tertiary reserves exist since this project did not have proved tertiary reserves prior to its implementation. We estimate the crude oil price necessary to sustain the long-term economic viability of this project is approximately $45-$50 per barrel. This price could vary based on several factors, including actual recovery rates and chemical costs.

Liquidity

At June 30, 2009, we had cash and cash equivalents of $0.4 million and working capital of $0.3 million. Our working capital balance included a $5.0 million derivative current asset and a $1.4 million deferred tax current liability. For the year ended June 30, 2009, we had net income applicable to common stock of $7.9 million and a loss from operations of $59.0 million, including a $26.7 million impairment of long-lived assets (see Note 14 to our Consolidated Financial Statements), $11.4 million of exploration expense (see Note 9 to our Consolidated Financial Statements) and $6.6 million of legal and settlement expenses in connection with the Panhandle fire litigation (see Note 17 to our Consolidated Financial Statements). For the year ended June 30, 2009, our cash used in operations of $6.6 million was negatively impacted by $10.7 million of settlement payments, net of reimbursements, related to the resolution of the Panhandle fire litigation.

We depend on our credit agreements, as described in Note 6 to our Consolidated Financial Statements, to fund a portion of our operating and capital needs. Under our senior credit agreement, the initial and current borrowing base, based upon our proved reserves, is $60.0 million. At June 30, 2009, our remaining available borrowing capacity under the senior credit agreement was $19.3 million,

Table of Contents

and at September 28, 2009, our remaining borrowing capacity was $13.8 million. Pursuant to the terms of our senior credit agreement, 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 as part of the redetermination process.

At June 30, 2009, we were in compliance with the debt covenants contained in each of our credit agreements. The 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 8 to our Consolidated Financial Statements). Based upon our six month operating results through June 30, 2009, we may not be in compliance with all of our financial covenants when we reach the twelve-month period ending December 31, 2009. If a combination of increased production, rising commodity prices, changes in our capital structure 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.

We have taken, and are considering taking, actions to ensure the aforementioned covenant compliance and sufficient liquidity to meet our obligations for the twelve months ending June 30, 2010, which includes funding our capital expenditure budget of $13.9 million. Actions we have taken during the six-month period ended June 30, 2009 to improve liquidity include: negotiating lower service rates with vendors, employee workforce reductions and shutting-in uneconomic wells. As discussed in Note 7 to our Consolidated Financial Statements, we have derivative contracts in place to protect us from falling crude oil and natural gas commodity prices on a portion of our production (through December 2012) and rising interest rates related to a portion of our outstanding debt (through January 2012). We are also considering credit and capital markets alternatives.

During each year of our prior five years in existence, we have successfully accessed the credit and capital markets to fund our operations and capital needs.

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) debt available under our credit agreements and (iv) our ability to access the equity markets, provide sufficient means to conduct our operations, meet our contractual obligations and undertake our capital expenditure program for the twelve months ending June 30, 2010 (as previously discussed in the section titled "Drilling Capital Development and Operating Activities Update"). To the extent that cash on hand as of June 30, 2009, cash flow generated by operations subsequent to June 30, 2009 and borrowings under our credit agreements are insufficient to fund our operating cash flow requirements and our capital expenditure plans, we will need to (i) raise capital through the issuance of debt or equity securities, (ii) refinance our existing credit arrangements, (iii)divest oil and gas property assets, (iv) reduce operating and capital expenditures and (v) pursue strategic alternatives. There can be no assurance that we will be successful in refinancing our credit arrangements or raising capital through the issuance of our debt or equity securities.

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.

Table of Contents

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, 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 Agreements

At June 30, 2009 and 2008, the outstanding amount due under our credit agreements was $55.7 million and $73.5 million, respectively. The $55.7 million at June 30, 2009, consisted of outstanding borrowings under the senior and subordinated credit agreements of $40.7 million and $15.0 million, respectively. At June 30, 2009, the average interest rates under the senior and subordinated credit agreements were 2.88% and 6.62%, respectively.

Our long-term debt consists of our senior credit facility (current borrowing base of $60.0 million) and our subordinated credit agreement ($15.0 million availability), which are discussed in greater detail below.

Senior Credit Agreement

On December 17, 2008, we finalized a new $120.0 million Amended and Restated Credit Agreement (the "ARCA") with Union Bank of North America, N.A. ("UBNA", f/k/a Union Bank of California, N.A.) and Natixis. UBNA is the Administrative Agent and Issuing Lender of the ARCA. The initial and current borrowing base, based upon our proved reserves, is $60.0 million. Pursuant to the terms of the ARCA, the borrowing base is to be redetermined based upon our reserves at June 30, 2009. Thereafter, there will be a scheduled redetermination every six months with one interim, additional redetermination allowed during any six month period between scheduled redeterminations at either the option of our lenders or us.

At our option, interest is either (i) the sum of (a) the UBNA reference rate and (b) the applicable margin of (1) 0.875% if less than 50% of the borrowing base is borrowed, (2) 1.125% if at least 50% but less than 75% of the borrowing base is borrowed, (3) 1.375% if at least 75% but less than 90% of the borrowing base is borrowed or (4) 1.625% if at least 90% of the borrowing base is borrowed; or (ii) the sum of (a) the one, two, three, six, nine or twelve month LIBOR rate (at our option) and (b) the applicable margin of (1) 2.0% if less than 50% of the borrowing base is borrowed, (2) 2.25% if at least 50% but less than 75% of the borrowing base is borrowed, (3) 2.50% if at least 75% but less than 90% of the borrowing base is borrowed or (4) 2.75% if at least 90% of the borrowing base is borrowed. We owe a commitment fee on the unborrowed portion of the borrowing base of 0.375% per annum if less than 90% of the borrowing base is borrowed and 0.50% per annum if at least 90% of the borrowing base is borrowed.

Unless specific events of default occur, the maturity date of the ARCA is December 17, 2012. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change.

Table of Contents

or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBNA, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBNA, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.

The ARCA contains three principal financial covenants with reconciliations to corresponding U.S. Generally Accepted Accounting Principles ("GAAP") amounts (if necessary):

•: A current ratio covenant that requires us to maintain a ratio of not less than 1.00 to 1.00 for each fiscal quarter. The current ratio is calculated by dividing current assets (as defined in the ARCA) by current liabilities (as defined in the ARCA). Current assets include unused borrowing base under the ARCA and the aggregate availability under the Subordinated Credit Agreement (as defined below). 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 June 30, 2009, our ratio of current assets to current liabilities was 2.74 to 1.00, calculated as follows (in thousands):

	June 30, 2009

Current assets (GAAP)	$	9,156
Unused borrowing base at June 30, 2009		19,300	(1)
Less: derivative assets		(4,955	)

Modified current assets (non-GAAP)	$	23,501	(A)

Current liabilities (GAAP)	$	8,815
Less: derivative liabilities		(159	)
Less: asset retirement obligation		(86	)

Modified current liabilities (non-GAAP)	$	8,570	(B)

Modified current ratio (A)/(B)		2.74 to 1.00

(1): Represents the $60.0 million borrowing base under the ARCA at June 30, 2009, less $40.7 million long-term debt outstanding under the ARCA at June 30, 2009.

•: A ratio of consolidated Debt (as defined in the ARCA) to consolidated EBITDA (as defined in the ARCA) covenant that requires us to maintain a ratio for the four fiscal quarter period then ended of not greater than 4.00 to 1.00. For the purposes of this ratio, Debt does not include amounts relating to our Series D Convertible Preferred Stock. At June 30, 2009, our ratio of consolidated Debt to EBITDA was 2.46 to 1.00, calculated as follows (in thousands):

	June 30, 2009

Long-term debt (GAAP)	$	55,700	(C)

Table of Contents

	Four Fiscal Quarter Period Ended June 30, 2009

Net loss (GAAP)	$	(231	)(2)
Depletion, depreciation and amortization		5,720
Interest expense, net		513
Income tax benefit		1,729	(2)
Other adjustments (non-GAAP)		14,897	(3)

EBITDA (non-GAAP)	$	22,628	(D)

Debt to EBITDA (C)/(D)		2.46 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 the ARCA, 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 fires litigation lawsuits and non-cash items included in the computation of income from discontinued operations.

•: A ratio of consolidated EBITDA (as defined in the ARCA) to consolidated Interest Expense (as defined in the ARCA) covenant for the four fiscal quarter period then ended that requires us to maintain a ratio of not less than 3.00 to 1.00. At June 30, 2009, our ratio of consolidated EBITDA to consolidated Interest Expense ratio was 8.27 to 1.00, calculated as follows (in thousands):

	Four Fiscal Quarter Period Ended June 30, 2009

EBITDA (non-GAAP) (see reconciliation above)	$	22,628	(E)

Interest expense (GAAP)	$	563
Capitalized interest		1,406
Cash payment of preferred stock dividends		1,145
Less: amortization of debt issuance costs		(377	)

Interest expense (non-GAAP)	$	2,737	(F)

EBITDA to interest expense (E)/(F)		8.27 to 1.00

The ARCA also contains customary events of default that would permit our lenders to accelerate the debt under the ARCA 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 June 30, 2009, we were in compliance with all of our covenants and had not committed any acts of default under the ARCA.

Subordinated Credit Agreement

On September 30, 2008, we paid off the entire outstanding $15.0 million principal due under the then existing subordinated credit agreement, interest expense and a prepayment premium of $0.3 million. In conjunction with the payoff, we terminated that subordinated credit agreement.

Table of Contents

On December 17, 2008, we finalized a new $25.0 million Subordinated Credit Agreement among Cano, the lenders and UnionBanCal Equities, Inc ("UBE") as Administrative Agent (the "Subordinated Credit Agreement"). On March 17, 2009, we borrowed the maximum available amount of $15.0 million under this agreement and paid down outstanding senior debt under the ARCA. An additional $10.0 million could be made available at the lender's sole discretion.

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

Unless specific events of default occur, the maturity date is June 17, 2013. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change as defined in the Subordinated Credit Agreement.

The Subordinated Credit Agreement contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests of Cano; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBE, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBE, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.

The Subordinated Credit Agreement contains four principal financial covenants:

•: A current ratio covenant that requires us to maintain a ratio of not less than 1.00 to 1.00 for each fiscal quarter. The current ratio is calculated by dividing current assets (as defined in the Subordinated Credit Agreement) by current liabilities (as defined in the Subordinated Credit Agreement). Current assets include unused borrowing base under the ARCA and the aggregate availability under the Subordinated Credit Agreement but excluding any cash deposited with or at the request of a party to any commodity derivative transactions and any assets representing a valuation account arising from application of SFAS 133 and 143. Current liabilities exclude current portions of debt other than any current debt relating to the Series D Convertible

Table of Contents

Preferred Stock and liabilities for asset retirement obligations. At June 30, 2009, our ratio of current assets to current liabilities was 2.74 to 1.00, calculated as follows (in thousands):

	June 30, 2009

Current assets (GAAP)	$	9,156
Unused borrowing base at June 30, 2009		19,300	(1)
Less: derivative assets		(4,955	)

Modified current assets (non-GAAP)	$	23,501	(A)

Current liabilities (GAAP)	$	8,815
Less: derivative liabilities		(159	)
Less: asset retirement obligation		(86	)

Modified current liabilities (non-GAAP)	$	8,570	(B)

Modified current ratio (A)/(B)		2.74 to 1.00

(1): Represents the $60.0 million borrowing base under the ARCA at June 30, 2009, less $40.7 million long-term debt outstanding under the ARCA at June 30, 2009.

•: A ratio of consolidated Debt (as defined in the Subordinated Credit Agreement) to consolidated EBITDA (as defined in the Subordinated Credit Agreement) covenant that requires us to maintain a ratio for the four fiscal quarter period then ended of not greater than 4.50 to 1.00. For the purposes of this ratio, Debt does not include amounts relating to our Series D Convertible Preferred Stock. At June 30, 2009, our ratio of consolidated Debt to EBITDA was 2.46 to 1.00, calculated as follows (in thousands):

	June 30, 2009

Long-term debt (GAAP)	$	55,700	(C)

	Four Fiscal Quarter Period Ended June 30, 2009

Net loss (GAAP)	$	(231	)(2)
Depletion, depreciation and amortization		5,720
Interest expense, net		513
Income tax benefit		1,729	(2)
Other adjustments (non-GAAP)		14,897	(3)

EBITDA (non-GAAP)	$	22,628	(D)

Debt to EBITDA (C)/(D)		2.46 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 the ARCA, 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 fires litigation lawsuits and non-cash items included in the computation of income from discontinued operations.

•: A ratio of consolidated EBITDA (as defined in the Subordinated Credit Agreement) to consolidated Interest Expense (as defined in the Subordinated Credit Agreement) covenant for the four fiscal quarter period then ended that requires us to maintain a ratio of not less than

Table of Contents

2.50 to 1.00. At June 30, 2009, our ratio of consolidated EBITDA to consolidated Interest Expense was 8.47 to 1.00, calculated as follows (in thousands):

	Four Fiscal Quarter Period Ended June 30, 2009

EBITDA (non-GAAP) (see reconciliation above)	$	22,628	(E)

Interest expense (GAAP)	$	563
Capitalized interest		1,406
Cash payment of preferred stock dividends		1,145
Less: amortization of debt issuance costs		(377	)

Interest expense (non-GAAP)	$	2,737	(F)

EBITDA to interest expense (E)/(F)		8.27 to 1.00

•: A minimum asset coverage ratio covenant that requires us to maintain a ratio of not less than 1.50 to 1.00. The minimum asset coverage ratio is calculated by dividing (i) Total Present Value as of the applicable determination date, which is defined as the sum of 100% of the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to (A) PDP reserves, (B) PDNP reserves and (C) PUD reserves, with the total present value of PDP reserves being at least 60% of the aggregate total present value, by (ii) consolidated Debt (as defined in the Subordinated Credit Agreement) as of the applicable determination date. At June 30, 2009, our minimum asset coverage ratio was 3.52 to 1.00, calculated as follows (in thousands):

	Quarter Ended June 30, 2009

Total present value (non-GAAP)	$	196,000	(G)

	June 30, 2009

Long-term debt (GAAP)	$	55,700	(H)

Total present value to debt (G)/(H)		3.52 to 1:00

The Subordinated Credit Agreement also contains customary events of default that would permit our lenders to accelerate the debt under the Subordinated Credit Agreement 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 ARCA. At June 30, 2009, we were in compliance with all of our covenants and had not committed any acts of default under the Subordinated Credit Agreement.

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.

Table of Contents

Results of Operations—Years Ended June 30, 2009, 2008 and 2007

Overall

For the 2009 Fiscal Year, we had income applicable to common stock of $7.9 million, which was a $29.5 million improvement as compared to the $21.6 million loss applicable to common stock for the 2008 Fiscal Year. Items that led to the improvement were increased gain on derivatives of $75.7 million, preferred stock repurchased for less than the carrying amount of $10.9 million, higher income from discontinued operations of $8.0 million and lower preferred stock dividend of $1.4 million. These positive factors were partially offset by higher operating expenses of $49.7 million, lower operating revenues of $9.3 million, lower deferred income tax benefit of $7.1 million and goodwill impairment of $0.7 million.

For the 2008 Fiscal Year, we had a loss applicable to common stock of $21.6 million, which was $17.6 million greater than the $4.0 million loss applicable to common stock incurred for the year ended June 30, 2007 (the "2007 Fiscal Year"). Increased revenues of $14.0 million, increased deferred tax benefit of $8.8 million and lower interest expense of $0.9 million were more than offset by higher loss on commodity derivatives of $31.1 million, higher operating expenses of $8.3 million, lower income from discontinued operations of $1.0 million and increased preferred stock dividend of $0.9 million.

Operating Revenues

The table below summarizes our operating revenues for the years ended June 30, 2009, 2008, and 2007.

								Increase (Decrease)

		Year Ended June 30,						Increase (Decrease)
		Year Ended June 30,						2009 v. 2008			2008 v. 2007
		2009		2008		2007		2009 v. 2008			2008 v. 2007
Operating Revenues (In Thousands)		$	25,409	$	34,650	$	20,651	$	(9,241	)	$	13,999
Sales:
	Crude Oil (MBbls)		309		249		223		60			26
	Natural Gas (MMcf)		776		908		824		(132	)		84
	MBOE		438		401		360		37			41
Average Realized Price
	Crude Oil ($/Bbl)	$	62.17	$	94.08	$	61.96	$	(31.91	)	$	32.12
	Natural Gas ($/Mcf)	$	7.57	$	11.99	$	8.29	$	(4.42	)	$	3.70
Operating Revenues and Commodity
	Derivative Settlements (In Thousands)	$	32,299	$	32,065	$	21,614	$	234		$	10,451
Average Adjusted Price (includes Commodity derivative settlements)
	Crude Oil ($/Bbl)	$	75.84	$	81.92	$	62.17	$	(6.08	)	$	19.75
	Natural Gas ($/Mcf)	$	10.23	$	12.48	$	9.41	$	(2.25	)	$	3.07

2009 Fiscal Year v. 2008 Fiscal Year

The 2009 Fiscal Year operating revenues of $25.4 million were $9.3 million lower as compared to the 2008 Fiscal Year operating revenues of $34.7 million. The $9.3 million reduction is primarily attributable to lower prices received for crude oil and natural gas sales, which lowered revenues by $8.0 million and $4.0 million, respectively, and by lower natural gas sales volumes, which lowered revenues by $1.0 million. These decreases were partially offset by increased crude oil sales volumes, which increased revenues by $3.7 million.

Table of Contents

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 2009 Fiscal Year as presented in the preceding table. As discussed in Note 7 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. For the 2009 Fiscal Year, approximately 82% of the increased crude oil sales of 60 MBbls were attributed to development activity at the Cato Properties, as previously discussed under the "Drilling Capital Development and Operating Activities Update." Also, we had increased crude oil sales from the Panhandle Properties due to development activity previously discussed under "Drilling Capital Development and Operating Activities Update."

Natural Gas Sales. For the 2009 Fiscal Year, the overall decrease in natural gas sales of 132 MMcf pertains primarily to reductions with respect to our Barnett Shale project at our Desdemona Properties. During the first half of calendar year 2008, various workovers and re-fracture stimulations were attempted to increase production. Through December 2008, these efforts were met with marginal success. In January 2009, we halted our workover program in the Desdemona Properties—Barnett Shale. Once the workover activity ceased, we experienced normal Barnett Shale annual production declines of approximately 65-90%. In July 2009, we shut-in our Barnett Shale natural gas wells and, based upon the current and near-term outlook of natural gas prices, we have no plans to return these wells to production in the foreseeable future.

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

Crude Oil and Natural Gas Prices. The average price we receive for crude oil sales is generally at market prices received at the wellhead, except for the Cato Properties, for which we receive below market prices due to the levels of impurities in the oil. Differentials gapped briefly as commodity prices rapidly declined between July 2008 and December 2008; however, the differentials have since recovered with the higher crude oil prices. 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 discussed in Note 7 to our Consolidated Financial Statements, we have commodity derivatives in place that provide for $80 to $85 crude oil "floor prices" and $7.75 to $8.00 natural gas "floor prices." If crude oil and natural gas NYMEX prices are lower than the "floor prices," we will be reimbursed by our counterparty for the difference between the NYMEX price and "floor price."

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

2008 Fiscal Year v. 2007 Fiscal Year

The 2008 Fiscal Year operating revenues of $34.7 million represent an improvement of $14.0 million as compared to the 2007 Fiscal Year operating revenues of $20.7 million. The $14.0 million improvement is primarily attributable to:

•: Higher realized prices received for crude oil and natural gas sales, as shown in the above table, which led to increases of $8.0 million and $3.3 million, respectively, and

Table of Contents

•: A full twelve months of Cato Properties operating revenues versus three months in 2007 Fiscal Year which contributed an additional $3.2 million to operating revenues.

Operating Expenses

2009 Fiscal Year v. 2008 Fiscal Year

For the 2009 Fiscal Year, our total operating expenses were $84.4 million, or $49.7 million higher than the 2008 Fiscal Year of $34.7 million. The primary contributors to the increase were an impairment of long-lived assets of $26.7 million and exploration expense of $11.4 million associated with the Desdemona Properties—Duke Sands waterflood project. In addition, we experienced increased lease operating expenses of $5.5 million, general and administrative of $4.3 million and higher depletion and depreciation of $1.8 million.

2008 Fiscal Year v. 2007 Fiscal Year

For the 2008 Fiscal Year, our total operating expenses were $34.7 million, or $8.3 million higher than the 2007 Fiscal Year of $26.4 million. The $8.3 million increase is primarily attributed to increased lease operating expenses of $4.6 million, higher general and administrative expenses of $2.2 million, higher production and ad valorem taxes of $0.8 million and increased depletion and depreciation expense of $0.7 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 2009 Fiscal Year, our LOE was $18.8 million, which is $5.5 million higher than 2008 Fiscal Year of $13.3 million. The $5.5 million increase resulted primarily from increased workover activities and general repairs at the Panhandle Properties of $4.2 million and higher operating expenses incurred at the Cato Properties of $2.1 million to support increased crude oil and natural gas sales, as discussed under "Operating Revenues," partially offset by lower operating expenses of $1.1 million due to lower natural gas sales at the Desdemona Properties, as discussed under "Operating Revenues." We also had higher LOE at the Davenport and Nowata Properties of $0.3 million due to increased electricity expenses, general repairs and workover expenses. The workover activities at the Panhandle Properties pertained to returning wells to production and have increased production, as discussed under "Operating Revenues," and are expected to result in increased production in future months.

For the 2009 Fiscal Year, our LOE per BOE, based on production, was $41.28 as compared to $32.69 for the 2008 Fiscal Year. In general, secondary and tertiary LOE is higher than the LOE for companies developing primary production because our fields are more mature and typically produce less oil and more water. We expect the LOE to decrease during the 2010 Fiscal Year as we realize the benefit of a full year of lower service rates 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." We did experience decreases in our LOE per BOE during the 2009 Fiscal Year as the LOE per BOE for the six months ended June 30, 2009 was $37.75, which is lower than the $44.84 LOE per BOE for the six months ended December 31, 2008.

For the 2008 Fiscal Year, our LOE was $13.3 million, which is $4.6 million higher as compared to the 2007 Fiscal Year LOE of $8.7 million. We incurred higher LOE due to the inclusion of the Cato Properties of $0.8 million, increased lifting costs at the Desdemona Properties of $1.7 million, increased workover rig expenses at the Panhandle and Pantwist Properties of $1.6 million and increased electricity expense of $0.7 million. Other factors contributing to higher LOE were increased crude oil and natural

Table of Contents

gas sales, as discussed under "Operating Revenues," and generally higher costs for goods and services. Our LOE for the 2008 Fiscal Year included a full year of Cato Properties' operating results versus three months in the 2007 Fiscal Year. Our LOE per BOE has increased from $23.47 during the 2007 Fiscal Year to $32.69 for the 2008 Fiscal Year, for the reasons previously discussed.

Production and Ad Valorem Taxes

For the 2009 Fiscal Year, our production and ad valorem taxes were $2.4 million, which is $0.1 million lower than the 2008 Fiscal Year of $2.5 million. Our production taxes were lower by $0.6 million due to lower operating revenues and were partially offset by increased ad valorem taxes of $0.5 million. The increased ad valorem taxes were due to notification of revisions in tax property valuations by taxing authorities for the 2008 calendar year. Therefore, the 2009 Fiscal Year includes higher tax rates for the twelve months plus a charge for applying the rates to the first six months of the 2008 calendar year. Our production taxes as a percent of operating revenues for the 2009 Fiscal Year of 6.5% was comparable to the 2008 Fiscal Years of 6.7%. We anticipate the 2010 Fiscal Year to be subject to similar production tax rates.

For the 2008 Fiscal Year, our production and ad valorem taxes were $2.5 million, which is $0.8 million higher than the 2007 Fiscal Year of $1.7 million. The $0.8 million increase is attributable to higher operating revenues, as previously discussed.

General and Administrative Expenses

Our general and administrative ("G&A") expenses consist of support services for our operating activities and investor relations costs.

2009 Fiscal Year v. 2008 Fiscal Year

For the 2009 Fiscal Year, our G&A expenses totaled $19.2 million, which is $4.3 million higher than Fiscal Year 2008 of $14.9 million. The primary contributors to the $4.3 million increase were higher litigation costs of $4.4 million pertaining to the settlement costs and legal fees pertaining of the fire litigation as discussed in Note 17 to our Consolidated Financial Statements and increased stock compensation expense of $0.2 million partially offset by reduced payroll expense of $0.3 million. During the quarter ended March 31, 2009, we took steps to reduce our payroll, eliminating 25% of our home office staff. The quarter ended June 30, 2009 was the first time we realized these savings.

Since we have settled all fire litigation claims except for one lawsuit, as discussed in Note 17 to our Consolidated Financial Statements, we expect significant decreases in future quarters' legal expenses. Also, the previously discussed workforce reductions are expected to reduce payroll and benefits costs by $0.8 million annually.

2008 Fiscal Year v. 2007 Fiscal Year

For the 2008 Fiscal Year, our G&A expenses totaled $14.9 million, which is $2.3 million higher than Fiscal Year 2007 of $12.6 million. The primary contributors to the $2.3 million increase were:

•: Increased stock compensation expense of $2.1 million resulting from the issuance of stock options as discussed in Note 10 to our Consolidated Financial Statements and the issuance of restricted shares as discussed in Note 11 to our Consolidated Financial Statements,
•: Increased labor and staffing costs of $0.3 million, which includes the accrual of bonuses earned during the 2008 Fiscal Year and the payment of bonuses during the quarter ended December 31, 2007, and

Table of Contents

•: Higher legal fees of $0.3 million pertaining to the fire litigation as discussed in Note 17 to our Consolidated Financial Statements.

These increases were partially offset by lower fees of $0.3 million for accounting services to achieve full compliance with Section 404 of the Sarbanes-Oxley Act and reductions totaling $0.1 million pertaining to other expenses.

Impairment of Long-Lived Assets

During the 2009 Fiscal Year, we recorded a $26.7 million impairment on our Barnett Shale Properties. As discussed in Note 14 to our Consolidated Financial Statements, the decline in commodity prices created an uncertainty in the likelihood of developing our reserves associated with our Barnett Shale natural gas properties within the next five years. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline and we shut-in our Barnett Shale natural gas wells. The fair value was determined using estimates of future production volumes, prices and operating expenses, discounted to a present value.

Exploration Expense

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

Depletion and Depreciation

For the 2009 Fiscal Year, our depletion and depreciation expense was $5.7 million, an increase of $1.8 million as compared to the 2008 Fiscal Year depletion and depreciation expense of $3.9 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 increased crude oil and natural gas sales volumes (net) as previously discussed under "Operating Revenues" and higher per BOE depletion rates. For the 2009 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $11.63 per BOE, as compared to the 2008 Fiscal Year rate of $8.19 per BOE. The increased depletion rates resulted from higher depletion rates for our Cato and Panhandle Properties based on our reserve redetermination at June 30, 2009 and periodic reassessments of depletion rates during the 2009 Fiscal Year.

For the 2008 Fiscal Year, our depletion and depreciation expense was $3.9 million, an increase of $0.7 million as compared to the 2007 Fiscal Year depletion and depreciation expense of $3.2 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 increased crude oil and natural gas sales volumes as previously discussed under "Operating Revenues" and higher per BOE depletion rates. For the 2008 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $8.19 per BOE, as compared to 2007 Fiscal Year rate of $6.91 per BOE. The higher depletion rates resulted from a reduction of reserves for the Desdemona—Barnett Shale and Pantwist Properties, as discussed in Note 18 to our Consolidated Financial Statements, and higher depletion rates attributed to the Cato Properties.

Table of Contents

Interest Expense and Other

For the 2009, 2008 and 2007 Fiscal Years, we incurred interest expense of $0.5 million, $0.8 million and $1.7 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 6 to our Consolidated Financial Statements. The interest expense for the 2009, 2008 and 2007 Fiscal Years was reduced by $1.4 million, $2.5 million and $0.3 million, respectively, for interest cost that was capitalized to the waterflood and ASP projects discussed under the "Drilling Capital Development and Operating Activities Update." We incurred higher interest costs during the 2008 Fiscal Year due to higher outstanding debt balances and higher interest rates.

Gain (Loss) on Commodity Derivatives

As discussed in Note 7 to our Consolidated Financial Statements, we have entered into financial contracts for our commodity derivatives and an interest rate swap arrangement. For the 2009 Fiscal Year, we recorded a gain on derivatives of $43.8 million as compared to losses of $32.0 million and $0.8 million for the 2008 and 2007 Fiscal Years, respectively. The 2009 Fiscal Year gain consisted of an unrealized gain of $36.9 million, a realized gain on settlements of commodity derivative contracts of $6.2 million and a $0.7 million realized gain on the sale of floor-priced contracts.

The 2008 Fiscal Year loss consists of unrealized and realized losses of $29.4 million and $2.6 million, respectively. For the 2007 Fiscal Year, we incurred an unrealized loss of $1.8 million and a realized gain of $1.0 million.

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

The unrealized gain for the 2009 Fiscal Year reflects the fair value of the commodity derivatives as of 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 $1.8 million.

Income Tax Benefit (Expense)

For the 2009 Fiscal Year, we had income tax expense of $1.7 million, as compared to an income tax benefit for the 2008 and 2007 Fiscal Years of $9.8 million and $0.4 million, respectively. These tax amounts included taxes related to discontinued operations as shown in Note 8 to our Consolidated Financial Statements. The increased income taxes for the 2009 Fiscal Year, as compared to the 2008 and 2007 Fiscal Years, is due to the increase in taxable income and an increase in the state tax rate and other permanent items, as presented in Note 16 to our Consolidated Financial Statements, resulting in an aggregate rate of 107.4%. The income tax rates for the 2008 and 2007 Fiscal Years was 35.9% for each year.

Income from Discontinued Operations

For the 2009, 2008 and 2007 Fiscal Years, we had income from discontinued operations of $11.5 million, $3.5 million and $4.5 million, respectively, due to our divestitures of the Pantwist, LLC; Corsicana Properties and Rich Valley Properties, as discussed in Note 8 to our Consolidated Financial Statements.

Table of Contents

Preferred Stock Dividend

The preferred stock dividend for the 2009 Fiscal Year of $2.7 million was a decrease of $1.4 million from $4.1 million for 2008 Fiscal Year. This resulted from the November and December 2008 repurchases of preferred stock as discussed in Note 5 to our Consolidated Financial Statements. Due to the repurchases, our quarterly preferred stock dividends will be approximately $0.5 million per quarter of which 59% will be PIK, with the remaining balance paid in cash. Also, the 2008 Fiscal Year amount includes $0.5 million of federal tax we were required to withhold in accordance with Internal Revenue Service regulations from September 2006 through June 2008. These amounts did not have a material effect to our prior period financial statements. Due to the previously discussed repurchases, we no longer have any Preferred Stock that required withholding taxes.

The preferred stock dividend for the 2008 Fiscal Year of $4.1 million was $0.9 million higher than the $3.2 million for the 2007 Fiscal Year. This is primarily due to $0.5 million federal tax withholding previously discussed.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at June 30, 2009 for the periods shown:

Amounts in $000s	Total		Less than 1 Year		1 To 3 Years		3 to 5 Years		More Than 5 Years

Long-term debt (See Note 6 to our Consolidated Financial Statements)	$	55,700	$	—	$	—	$	55,700	$	—
Series D Preferred Stock		26,987		—		26,987		—		—
Operating lease obligations (See Note 17 to our Consolidated Financial Statements)		3,048		516		1,233		1,299		—

Total contractual obligations	$	85,735	$	516	$	28,220	$	56,999	$	—

Off Balance Sheet Arrangements

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

Table of Contents

Selected Quarterly Financial Data (Unaudited)

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

In thousands, except per share data Fiscal Year Ended June 30, 2009	Sept. 30(a)			Dec. 31(b)			Mar. 31			Jun. 30(c)

Operating revenues from continuing operations	$	10,932		$	4,876		$	3,928		$	5,673
Operating loss from continuing operations		(1,335	)		(33,703	)		(4,332	)		(19,645	)
Loss from continuing operations		13,607			(8,628	)		(704	)		(15,986	)
Income (loss) from discontinued operations, net of tax		(853	)		12,246			(5	)		92
Net income (loss) applicable to common stock		11,818			13,653			(1,179	)		(16,363	)
Net income (loss) per share—basic		0.26			0.30			(0.03	)		(0.36	)
Net income (loss) per share—diluted		0.23			0.27			(0.03	)		(0.36	)

Fiscal Year Ended June 30, 2008	Sept. 30			Dec. 31			Mar. 31			Jun. 30(d)

Operating revenues from continuing operations	$	6,586		$	7,696		$	9,173		$	11,195
Operating income (loss) from continuing operations		(1,008	)		(155	)		613			507
Loss from continuing operations		(931	)		(1,412	)		(1,995	)		(16,654	)
Income from discontinued operations, net of tax		652			722			946			1,151
Net loss applicable to common stock		(1,246	)		(1,578	)		(1,926	)		(16,854	)
Net loss per share—basic and diluted		(0.04	)		(0.04	)		(0.05	)		(0.47	)

(a): For the quarter ended September 30, 2008, our results of operations were favorably impacted by $24.2 million unrealized gain on commodity derivatives resulting from a significant price decrease for both crude oil and natural gas.
(b): For the quarter ended December 31, 2008, our results of operations were unfavorably impacted by impairment of long-lived assets of $22.4 million, partially offset by unrealized gain on commodity derivatives.
(c): For the quarter ended June 30, 2009, our results of operations were unfavorably impacted by exploration expense of $11.4 million and impairment of long-lived assets of $4.3 million.
(d): For the quarter ended June 30, 2008, our results of operations were unfavorably impacted by $23.8 million unrealized loss on commodity derivatives resulting from a significant price increase for both crude oil and natural gas.

Critical Accounting Policies

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

We prepared our consolidated financial statements in accordance with United States generally accepted accounting principles ("GAAP"). GAAP requires management to make judgments and estimates, including choices between acceptable GAAP alternatives.

Table of Contents

Oil and Gas Properties and Equipment

We follow the successful efforts method of accounting. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense. The costs of drilling and equipping exploratory wells are deferred until the company has determined whether proved reserves have been found. If proved reserves are found, the deferred costs are capitalized as part of the wells and related equipment and facilities. If no proved reserves are found, the deferred costs are charged to expense. All development activity costs are capitalized. We are primarily engaged in the development and acquisition of crude oil and natural gas properties. Our activities are considered development where existing proved reserves are identified prior to commencement of the project and are considered exploration if there are no proved reserves at the beginning of such project. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisition and development activities and deferred exploratory drilling costs. Capitalized overhead costs that directly relate to our drilling and development activities were $1.1 million and $0.8 million, for the years ended June 30, 2009 and 2008, respectively. We recorded capitalized interest costs of $1.4 million and $2.5 million for the years ended June 30, 2009 and 2008, respectively.

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

Depreciation and depletion of producing properties are computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Our unit-of-production amortization rates are revised prospectively on a quarterly basis based on updated engineering information for our proved developed reserves. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until impairment occurs. As of June 30, 2009 and 2008, capitalized costs related to waterflood and ASP projects that were in process and not subject to depletion amounted to $49.4 million and $47.6 million, respectively, of which $4.8 million and $13.1 million, respectively, were deferred costs related to drilling and equipping exploratory wells as discussed in Note 9 to our Consolidated Financial Statements.

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

Asset Retirement Obligation

Our financial statements reflect the fair value for any asset retirement obligation, consisting of future plugging and abandonment expenditures related to our oil and gas properties, which can be reasonably estimated. The asset retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations.

Table of Contents

Estimates of Proved Reserves

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

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

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

Revenue Recognition

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

As previously discussed, for the years ended June 30, 2009, 2008 and 2007, we sold our crude oil and natural gas production to several independent purchasers. The following table shows purchasers that accounted for 10% or more of our total revenues:

	Year Ended June 30,

	2009			2008			2007
Valero Marketing Supply Co.		32	%		33	%		36	%
Coffeeville Resources Refinery and Marketing, LLC		18	%		15	%		16	%
Plains Marketing, LP		15	%		*			*
Eagle Rock Field Services, LP		13	%		18	%		18	%
DCP Midstream, LP		10	%		14	%		17	%

*: Less than 10% of operating revenue

Table of Contents

not expect the loss of any single purchaser to have a long-term material adverse effect on our operations, though we may experience a short-term decrease in our revenues as we make arrangements for alternative purchasers. However, the loss of a single purchaser could potentially reduce the competition for our crude oil and natural gas production, which could negatively impact the prices we receive.

Stock-Based Compensation Expense

We account for share-based payment arrangements with employees and directors at their grant-date fair value and record the related expense over their respective vesting periods. The value of stock-based compensation is impacted by our stock price, which has been highly volatile, and items that require management's judgment, such as expected lives and forfeiture rates.

Derivatives

We are required to hedge a portion of our production at specified prices for oil and natural gas under our senior and subordinated credit agreements, as discussed in Note 6 to our Consolidated Financial Statements. The purpose of the derivatives is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect our cash flows which support our annual capital expenditure plans. We have entered into commodity derivatives that involve "costless collars" for our crude oil and natural gas sales. These derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets based upon their respective fair values. We have entered into an interest rate basis swap contract to reduce our exposure to future interest rate increases.

We do not designate our derivatives as cash flow or fair value hedges. We do not hold or issue derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparties to our commodity and interest rate swap derivatives. We anticipate, however, that our counterparties will be able to fully satisfy their respective obligations under our commodity and interest rate swap derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts nor are we required to post any collateral. We monitor the credit standing of our counterparties to understand our credit risk.

Changes in the fair values of our derivative instruments and cash flows resulting from the settlement of our derivative instruments are recorded in earnings as gains or losses on derivatives on our consolidated statements of operations.

New Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141 (revised 2007), Business Combinations ("SFAS No. 141R"). Among other things, SFAS No. 141R 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. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted SFAS No. 141R on July 1, 2009. This standard will change our accounting treatment for prospective business combinations.

Table of Contents

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. We do not expect the adoption of this statement will have a material impact on our financial position, results of operations or cash flows.

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

In June 2008, the FASB issued EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP 03-6-1"). FSP 03-6-1 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 described in SFAS No. 128, Earnings per Share. Under FSP 03-6-1, share-based payment awards that contain nonforfeitable rights to dividends are "participating securities" as defined by EITF 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128, and therefore should be included in computing earnings per share using the two-class method. FSP 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted FSP 03-6-1 on July 1, 2009. The effect of adopting FSP 03-6-1 will increase the number of shares used to compute earnings per share; however, we do not expect the adoption of FSP 03-6-1 to have a material impact on our financial position, results of operations or cash flows.

In December 2008, the FASB issued EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock ("EITF 07-5"). EITF 07-5 affects companies that have provisions in their securities purchase agreements (for warrants and convertible instruments) that reset issuance/conversion prices based upon new issuances by companies at prices below the exercise 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 under SFAS No. 133. Subject to certain exceptions, our Preferred Stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. EITF 07-5 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted EITF 07-5 on July 1, 2009. We do not expect the adoption of this statement to have a material impact on our financial position, results of operations or cash flows. Had we adopted EITF 07-5 on June 30, 2009, we estimate that we would have reduced our temporary equity by approximately $0.7 million to $1.0 million and recorded a derivative liability for the same $0.7 million to $1.0 million amount, which would be marked-to-market for future reporting periods.

In June 2009, the FASB issued SFAS 165, Subsequent Events ("SFAS 165") 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, SFAS 165 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. SFAS 165 is effective for financial statements issued for interim or annual periods ending after June 15, 2009. We adopted SFAS 165 on June 30,

Table of Contents

2009 and considered subsequent events through September 28, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS 168, Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles ("SFAS 168"). SFAS 168 replaces SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principle. SFAS 168 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with generally acceptable accounting principles. SFAS 168 is effective for financial statements for interim and annual periods ending on or after September 15, 2009. We adopted SFAS 168 on July 1, 2009. We do not expect the adoption of this statement to have a material impact on our financial position, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Pursuant to our credit agreements, we are subject to risks associated with interest rate fluctuations, as described under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreements." We have partially mitigated this risk by implementing an interest rate swap agreement, as discussed in Note 7 to our Consolidated Financial Statements. This agreement is effective through January 12, 2012 and establishes a fixed 1.73% LIBOR rate for $20.0 million in notional exposure. During our fiscal year ended June 30, 2009, if there had been an increase in the interest rate of 1%, our total interest cost would have increased by $0.3 million annually.

Commodity Risk

Our revenues are derived from the sale of our crude oil and natural gas production. The prices for oil and natural gas are extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Pursuant to our senior and subordinated credit agreements discussed in Note 6 to our Consolidated Financial Statements, we are required to maintain our existing commodity derivative contracts, all of which have UBNA as our counterparty. 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. Therefore, for the hedged production, we will receive at least the floor prices. As of June 30, 2009, we maintained the following commodity derivative contracts:

Time Period	Floor Oil Price		Ceiling Oil Price			Floor Gas Price		Ceiling Gas Price

7/1/09 - 12/31/09	$	80.00	$	110.90	367	$	7.75	$	10.60	1,667	644
7/1/09 - 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

Assuming that the prices that we receive for our crude oil and natural gas production are above the floor prices, based on our actual fiscal year sales volumes for the year ended June 30, 2009, a 10% decline in the prices we receive for our crude oil and natural gas production would have had an approximate $2.5 million negative impact on our revenues.

Table of Contents

We computed our mark-to-market valuations used for our commodity derivatives based on assumptions regarding forward prices, volatility and the time value of money. We compared our valuations to our counterparties' valuations to further validate our mark-to-market valuations. During the year ended June 30, 2009, we recognized an unrealized gain on commodity derivatives in our consolidated statements of operations amounting to $36.8 million. During the years ended June 30, 2008 and 2007, we recognized an unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $29.4 million and $1.8 million, respectively.

If crude oil prices fell $1 below our hedged crude oil price floor, we would receive approximately $0.2 million annually due to having the crude oil price floor hedge in place. If natural gas prices fell $1 below our hedged natural gas price floor, we would receive approximately $1.1 million annually due to having the natural gas price floor hedge in place.

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

Time Period	Fixed Oil Price

4/1/11 - 12/31/11	$	75.90	700
1/1/12 - 12/31/12	$	77.25	700

Item 8. Financial Statements and Supplementary Data.

The Report of Independent Registered Public Accounting Firm and Consolidated Financial Statements are set forth beginning on page F-1 of this annual report on Form 10-K and are incorporated herein.

The financial statement schedules have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes to our Consolidated Financial Statements.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) that are designed to ensure that information required to be disclosed by us in the reports filed or submitted under the Securities Exchange Act of 1934 is (i) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and (ii) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based on that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures as of June 30, 2009 were effective.

Table of Contents

Management's Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethics and Business Conduct for Officers, Directors and Employees, which sets the tone of our Company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail accurately and fairly reflect our acquisitions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

In order to evaluate the effectiveness of our internal control over financial reporting as of June 30, 2009, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the "COSO Framework"). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, determined that our internal control over financial reporting was effective as of June 30, 2009 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Hein & Associates LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued an attestation report on the Company's internal control over financial reporting as of June 30, 2009. Their report, dated September 28, 2009, which expressed an opinion that the Company had maintained effective internal control over financial reporting as of June 30, 2009 based on criteria established in the COSO Framework, is included below.

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
Cano Petroleum, Inc.

We have audited Cano Petroleum Inc.'s internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Cano Petroleum Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Cano Petroleum, Inc. maintained, in all material respects, effective internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries as of June 30, 2009 and 2008, and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended June 30, 2009 and our report dated September 28, 2009 expressed an unqualified opinion.

/s/ HEIN & ASSOCIATES LLP

Dallas, Texas
September 28, 2009

Table of Contents

Changes in Internal Controls

During the quarter ended June 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.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Information required by this item relating to our (i) directors and executive officers, (ii) audit committee, (iii) Code of Ethics and Business Conduct, (iv) changes in procedures by which security holders may recommend nominees to our board of directors, and (v) compliance with Section 16(a) of the Securities Exchange Act will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to our 2009 annual meeting of stockholders and will be incorporated herein by reference.

Item 11. Executive Compensation.

Information required by this item relating to executive compensation will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2009 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information required by this item relating to (i) security ownership of certain beneficial owners and management and (ii) securities authorized for issuance under equity compensation plans will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2009 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Information required by this item relating to (i) certain business relationships and related transactions with management and other related parties and (ii) director independence will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2009 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information relating to (i) fees billed to the Company by the independent registered public accounting firm for services for the years ended June 30, 2009 and 2008 and (ii) the audit committee's pre-approval policies and procedures for audit and non-audit services, will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to our 2009 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.

Table of Contents

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as part of this report:

1.: Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of June 30, 2009 and 2008, Consolidated Statements of Operations for each of the three years in the period ended June 30, 2009, Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended June 30, 2009, Consolidated Statements of Cash Flows for each of the three years in the period ended June 30, 2009, and Notes to Consolidated Financial Statements.
2.: The financial statement schedules have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes to Consolidated Financial Statements.
3.: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.



	CANO PETROLEUM, INC.

Date: September 28, 2009	By:	/s/ S. JEFFREY JOHNSON S. Jeffrey Johnson Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Date: September 28, 2009	By:	/s/ BENJAMIN DAITCH Benjamin Daitch Senior Vice-President and Chief Financial Officer
Date: September 28, 2009	By:	/s/ MICHAEL J. RICKETTS Michael J. Ricketts Vice-President and Principal Accounting Officer

Table of Contents

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned directors of Cano Petroleum, Inc. hereby constitutes and appoints S. Jeffrey Johnson and Benjamin Daitch or either of them (with full power to each of them to act alone), his true and lawful attorney-in-facts and agents, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file any and all amendments to this Form 10-K, with all exhibits thereto, and other documents in connection therewith, with the SEC, granting unto said attorneys, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as full to all intents and purposes as he himself might or could do if personally present, thereby ratifying and confirming all that said attorneys-in-fact and agents, or either of them, or their or his substitute or substitutes, may lawfully do or cause to be done.

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date


/s/ S. JEFFREY JOHNSON S. Jeffrey Johnson	Chairman of the Board	September 28, 2009
/s/ RANDALL BOYD Randall Boyd	Director	September 28, 2009
/s/ ROBERT L. GAUDIN Robert L. Gaudin	Director	September 28, 2009
/s/ DONALD W. NIEMIEC Donald W. Niemiec	Director	September 28, 2009
/s/ WILLIAM O. POWELL III William O. Powell III	Director	September 28, 2009
/s/ STEVEN J. PULLY Steven J. Pully	Director	September 28, 2009
/s/ GARRETT SMITH Garrett Smith	Director	September 28, 2009
/s/ DAVID W. WEHLMANN David W. Wehlmann	Director	September 28, 2009

Table of Contents

INDEX TO EXHIBITS

		Description

2.1		Agreement and Plan of Merger made as of the 26^th day of May 2004, among Huron Ventures, Inc., Davenport Acquisition Corp., Davenport Field Unit Inc., the shareholders of Davenport Field Unit Inc., Cano Energy Corporation and Big Sky Management Ltd., incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K filed with the SEC on June 8, 2004.
2.2	+	Management Stock Pool Agreement dated May 28, 2004 among Huron Ventures Inc. and the Shareholders of Davenport Field Unit Inc., incorporated herein by reference to Exhibit 2.2 to the Amendment to the Company's Current Report on Form 8-K/A filed with the SEC on August 11, 2004.
2.3	+	Investment Escrow Agreement dated May 28, 2004 among Cano Energy Corporation, Huron Ventures Inc. and Phillip A. Wylie, incorporated herein by reference to Exhibit 2.3 to the Amendment to the Company's Current Report on Form 8-K/A filed with the SEC on August 11, 2004.
2.4		Stock Purchase Agreement dated June 30, 2004 between Cano Petroleum, Inc., as Buyer, and Jerry D. Downey and Karen S. Downey, as Sellers, incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K filed with the SEC on July 15, 2004.
2.5		Purchase and Sale Agreement dated August 16, 2004 between Cano Energy Corporation and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on August 25, 2004.
2.6		Purchase and Sale Agreement dated September 2, 2004 between Nowata Oil Properties LLC and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on September 20, 2004.
2.7		Purchase and Sale Agreement dated February 6, 2005 between Square One Energy, Inc. and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on March 7, 2005.
2.8		Stock Purchase Agreement dated November 29, 2005 among Cano Petroleum, Inc., W. O. Energy of Nevada, Inc., Miles O'Loughlin and Scott White, incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the SEC on December 5, 2005. All schedules and exhibits have been omitted from this filing. A list of the schedules and exhibits is contained in the Stock Purchase Agreement, and the Company agrees to furnish a copy of the omitted schedules and exhibits to the SEC upon request.
2.9		Asset Purchase and Sale Agreement dated April 25, 2006 among Myriad Resources Corporation, Westland Energy Company and PAMTEX, a Texas general partnership composed of PAMTEX GP1 Ltd. and PAMTEX GP2 Ltd., as Sellers, and Cano Petroleum, Inc. as Buyer, incorporated herein by reference to Exhibit 2.1 to the Company's Quarterly Report on Form 10-QSB filed with the SEC on May 15, 2006. All schedules and exhibits, except for Schedule 1.1, have been omitted from this filing. A list of the schedules and exhibits is contained in the Asset Purchase and Sale Agreement, and the Company agrees to furnish a copy of the omitted schedules and exhibits to the SEC upon request.

Table of Contents

Exhibit Number			Description

	2.10		Purchase and Sale Agreement dated March 30, 2007 among UHC New Mexico Corporation, as Seller, Cano Petro of New Mexico, Inc., as Buyer, and Cano Petroleum, Inc., for Certain Limited Purposes, incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the SEC on April 4, 2007. All schedules and exhibits, except for Schedule 1.1, have been omitted from this filing. A list of the schedules and exhibits is contained in the Purchase and Sale Agreement, and the Company agrees to furnish a copy of the omitted schedules and exhibits to the SEC upon request.
	2.11		Agreement for Purchase and Sale dated June 1, 2007 among Ladder Companies, Inc. and Tri-Flow, Inc., as Seller, and Anadarko Minerals, Inc., as Buyer, incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the SEC on June 12, 2007. (All annexes and exhibits, except for Annexes I and II have been omitted from this filing. A list of annexes and exhibits is contained in the Agreement for Purchase and Sale, and the Company agrees to furnish a copy of the omitted annexes and exhibits to the SEC upon request).
	2.12		Purchase and Sale Agreement dated September 5, 2008 among Cano Petroleum, Inc., as Seller, and Legacy Reserves Operating LP, as Buyer, and Pantwist, LLC, incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the SEC on October 6, 2008. All schedules and exhibits have been omitted from this filing. A list of the schedules and exhibits is contained in the Purchase and Sale Agreement, and the Company agrees to furnish a copy of the omitted schedules and exhibits to the SEC upon request.
	2.13		First Amendment dated September 30, 2008 to the Purchase and Sale Agreement among Cano Petroleum, Inc., as Seller, and Legacy Reserves Operating LP, as Buyer, and Pantwist, LLC, as the Company, dated September 5, 2008, incorporated herein by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K filed with the SEC on October 6, 2008. All exhibits have been omitted from this filing. A list of the exhibits is contained in the First Amendment, and the Company agrees to furnish a copy of the omitted exhibits to the SEC upon request.
	3.1		Certificate of Incorporation of Huron Ventures, Inc., incorporated herein by reference to Exhibit 3.1 to the Company's Registration Statement on Form 10 SB (File No. 000-50386) filed with the SEC on September 4, 2003.
	3.2		Certificate of Ownership of Huron Ventures, Inc. and Cano Petroleum, Inc., amending the Company's Certificate of Incorporation, incorporated herein by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-KSB filed with the SEC on September 23, 2004.
	3.3		Certificate of Amendment to Certificate of Incorporation of Cano Petroleum, Inc., incorporated herein by reference to Exhibit 3.8 to the Company's Post-Effective Amendment No. 2 on Form S-1 filed with the SEC on January 23, 2007.
	3.4		First Amended and Restated Bylaws of Cano Petroleum, Inc., incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the SEC on December 7, 2007.
	3.5		Amendment to Amended and Restated Bylaws, dated October 20, 2008, incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the SEC on October 24, 2008.

Table of Contents

		Description

3.6		Second Amended and Restated By-Laws of Cano Petroleum, Inc. dated May 7, 2009, incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the SEC on May 13, 2009.
3.7		Certificate of Designation for Series B Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed with the SEC on June 8, 2004.
3.8		Certificate of Designation for Series C Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed with the SEC on July 15, 2004.
3.9		Certificate of Designation for Series D Convertible Preferred Stock incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the SEC on September 7, 2006.
4.1		Registration Rights Agreement dated August 25, 2006 among Cano Petroleum, Inc. and the Buyers listed therein, incorporated herein by reference to Exhibit 4.1 to the Amendment to the Company's Current Report on Form 8-K/A filed with the SEC on August 31, 2006.
4.2		Registration Rights Agreement dated November 2, 2007 among Cano Petroleum, Inc. and the Buyers listed therein, incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed with the SEC on November 6, 2007.
4.3		Form of Common Stock certificate, incorporated herein by reference to Exhibit 4.9 to the Company's Registration Statement on Form S-3 (No. 333-148053) filed with the SEC on December 13, 2007.
4.4		Designation for Series A Convertible Preferred Stock, included in the Certificate of Incorporation of Huron Ventures, Inc., incorporated herein by reference to Exhibit 3.1 to the Company's registration statement on Form 10 SB (File No. 000-50386) filed with the SEC on September 4, 2003.
4.5		Certificate of Designation for Series B Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed with the SEC on June 8, 2004.
4.6		Certificate of Designation for Series C Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed with the SEC on July 15, 2004.
4.7		Certificate of Designation for Series D Convertible Preferred Stock incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the SEC on September 7, 2006.
10.1	+	Stock Option Agreement dated December 16, 2004 between Cano Petroleum, Inc. and Gerald W. Haddock, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on December 16, 2004.
10.2	+	2005 Directors' Stock Option Plan, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on June 28, 2005.

Table of Contents

		Description

10.3		$100,000,000 Credit Agreement dated November 29, 2005 among Cano Petroleum, Inc., as Borrower, The Lenders Party Thereto From Time to Time, as Lenders, and Union Bank of California, N.A., as Administrative Agent and as issuing Lender, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on December 5, 2005.
10.4		Guaranty Agreement dated November 29, 2005 among Ladder Companies, Inc., Square One Energy, Inc., W.O. Energy of Nevada, Inc., W.O. Energy, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd. in favor of Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the SEC on December 5, 2005.
10.5		Escrow Agreement dated November 29, 2005 among Cano Petroleum, Inc., Miles O'Loughlin, Scott White and The Bank of New York Trust Company, N.A., as Escrow Agent, incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the SEC on December 5, 2005.
10.6		Amended and Restated Escrow Agreement dated June 18, 2007 among Cano Petroleum, Inc., the Estate of Miles O'Loughlin and Scott White, and The Bank of New York Trust Company, N.A., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on June 21, 2007.
10.7		Pledge Agreement dated November 29, 2005 among Cano Petroleum, Inc., W. O. Energy of Nevada, Inc. and WO Energy, Inc. in favor of Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K dated on December 5, 2005.
10.8		Security Agreement dated November 29, 2005 among Cano Petroleum, Inc., Ladder Companies Inc., Square One Energy, Inc., W. O. Energy of Nevada, Inc., WO Energy, Inc., W. O. Operating Company, Ltd. and W. O. Production Company, Ltd., in favor of Union Bank of California N.A., as Collateral Trustee, incorporated herein by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed with the SEC on December 5, 2005.
10.9	+	Cano Petroleum, Inc. 2005 Long-Term Incentive Plan dated December 7, 2005, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on December 9, 2005.
10.10	+	Form of Non-Qualified Stock Option Agreement under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on December 19, 2005.
10.11	+	Employment Agreement dated effective January 1, 2006 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on January 19, 2006.
10.12		Amendment No. 1 dated February 24, 2006 to the $100,000,000 Credit Agreement dated November 29, 2005 among Cano Petroleum, Inc., as Borrower, The Lenders Party Thereto From Time to Time as Lenders and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on March 1, 2006.

Table of Contents

		Description

10.13		Amendment No. 2, Assignment and Agreement dated April 28, 2006 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Pantwist, LLC, Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Assignee, and Natexis Banques Populaires, as a Lender and as the Assignor, incorporated herein by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-QSB filed with the SEC on May 15, 2006.
10.14		Supplement No. 1 dated April 28, 2006 to the Pledge Agreement dated November 29, 2005, by Cano Petroleum, Inc., W.O. Energy of Nevada, Inc. and WO Energy, Inc. in favor of Union Bank of California, N.A., as Collateral Trustee, incorporated herein by reference to Exhibit 10.11 to the Company's Quarterly Report on Form 10-QSB filed with the SEC on May 15, 2006.
10.15		Amendment No. 3 to Credit Agreement among Cano Petroleum, Inc., a Borrower, Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc. Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natexis Banques Populaires dated May 12, 2006 and effective as of March 31, 2006, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on May 15, 2006.
10.16	+	Employment Agreement of Morris B. Smith effective June 1, 2006, incorporated herein by reference to Exhibit 10.1 on Current Report on Form 8-K filed with the SEC on June 6, 2006.
10.17	+	Employee Restricted Stock Award Agreement of Morris B. Smith effective June 1, 2006, incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the SEC on June 6, 2006.
10.18	+	Employment Agreement of Patrick M. McKinney effective June 1, 2006, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on November 9, 2006.
10.19	+	First Amendment to Employment Agreement of Patrick M. McKinney dated November 9, 2006, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on November 9, 2006.
10.20	+	Restricted Stock Award Agreement of Patrick M. McKinney dated June 1, 2006, incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the SEC on November 9, 2006.
10.21		Amendment No. 4 to Credit Agreement among Cano Petroleum, Inc., as Borrower, Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natexis Banques Populaires dated June 30, 2006, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on July 7, 2006.
10.22	+	Employment Agreement of Michael J. Ricketts effective July 1, 2006, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on August 17, 2006.

Table of Contents

		Description

10.23	+	Employee Restricted Stock Award Agreement of Morris B Smith dated August 11, 2006, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on August 17, 2006.
10.24		Securities Purchase Agreement dated August 25, 2006 among Cano Petroleum, Inc. and the Buyers listed therein, incorporated herein by reference to Exhibit 10.1 to the Amendment to the Company's Current Report on Form 8-K/A filed with the SEC on August 31, 2006.
10.25	+	Amendment No. 1 to the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan dated December 28, 2006, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.26	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.27	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and Morris B. Smith, incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.28	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and Patrick M. McKinney, incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.29	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and James K. Teringo, Jr., incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.30	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and Michael J. Ricketts, incorporated herein by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.31	+	Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and Gerald Haddock, incorporated herein by reference to Exhibit 10.75 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.32	+	Nonqualified Stock Option Agreement of Donnie Dale Dent dated December 28, 2006, incorporated herein by reference to Exhibit 10.76 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.33	+	Nonqualified Stock Option Agreement of Randall C. Boyd dated December 28, 2006, incorporated herein by reference to Exhibit 10.77 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.34	+	Nonqualified Stock Option Agreement of James Dale Underwood dated December 28, 2006, incorporated herein by reference to Exhibit 10.78 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.

Table of Contents

		Description

10.35	+	Nonqualified Stock Option Agreement of Patrick W. Tolbert dated December 28, 2006, incorporated herein by reference to Exhibit 10.79 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.36	+	Nonqualified Stock Option Agreement of Dennis McCuistion dated December 28, 2006, incorporated herein by reference to Exhibit 10.80 to the Company's Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.37		Amendment No. 5 and Agreement dated March 6, 2007 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender, and Natixis, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on March 12, 2007.
10.38		Supplement No. 2 dated March 6, 2007 to the Security Agreement dated November 29, 2005 by Cano Petro of New Mexico, Inc. in favor of Union Bank of California, as Collateral Trustee, incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the SEC on March 12, 2007.
10.39		Supplement No. 2 dated March 6, 2007 to the Guaranty Agreement dated November 29, 2005 by Cano Petro of New Mexico, Inc. in favor of Union Bank of California, as Administrative Agent, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on March 12, 2007.
10.40		Supplement No. 2 dated March 6, 2007 to the Pledge Agreement dated November 29, 2005 by Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., and WO Energy, Inc. in favor of Union Bank of California, as Collateral Trustee, incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the SEC on March 12, 2007.
10.41		Assignment and Agreement dated March 7, 2007 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender, and Natixis, incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the SEC on March 12, 2007.
10.42	+	Nonqualified Stock Option Agreement of William O. Powell III dated April 4, 2007, incorporated herein by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.
10.43	+	Nonqualified Stock Option Agreement of Robert L. Gaudin dated April 4, 2007, incorporated herein by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.
10.44	+	Nonqualified Stock Option Agreement of Donald W. Niemiec dated April 4, 2007, incorporated herein by reference to Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.

Table of Contents

		Description

10.45		Settlement Agreement and Release dated February 9, 2007 among Mid-Continent Casualty Company, Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd., W.O. Energy, Inc., Ladder Energy Companies, Inc., and Square One Energy, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Post-Effective Amendment No. 1 on Form S-3 (File No. 333-138003) filed with the SEC on April 9, 2007.
10.46	+	Separation Agreement, General Release and Covenant Not to Sue dated May 22, 2007 between Cano Petroleum, Inc. and James K. Teringo, Jr., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on May 25, 2007.
10.47	+	Form of Restricted Stock Award under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on July 2, 2007.
10.48	+	Form of Nonqualified Stock Option Agreement under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on July 2, 2007.
10.49	+	First Amendment to Employment Agreement of Morris B. Smith dated June 29, 2007, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on July 3, 2007.
10.50	+	Second Amendment to Employment Agreement of Patrick M. McKinney dated June 29, 2007, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on July 3, 2007.
10.51	+	First Amendment to Employment Agreement of Michael J. Ricketts dated June 29, 2007, incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the SEC on July 3, 2007.
10.52	+	Form of the First Amendment to the Cano Petroleum, Inc. Employee Restricted Stock Award Agreement, incorporated herein by reference to Exhibit 10.96 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.53	+	Form of Restricted Stock Award under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.97 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.54		Amendment No. 6 dated August 13, 2007 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender, and Natixis, incorporated herein by reference to Exhibit 10.98 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.

Table of Contents

		Description

10.55		First Amendment to the Security Agreement dated July 9, 2007, among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd. and Union Bank of California, N.A., as Senior Agent, incorporated herein by reference to Exhibit 10.99 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.56		First Amendment to the Pledge Agreement dated July 9, 2007, among Cano Petroleum, Inc., W.O. Energy of Nevada, Inc. and WO Energy, Inc. and Union Bank of California, N.A., as Senior Agent, incorporated herein by reference to Exhibit 10.100 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.57	+	Audit Committee Chairman Compensation (June 2007), incorporated herein by reference to Exhibit 10.101 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.58		Summary of Acceleration of Vesting and Extension of Exercise Period for Stock Options for Resigning Directors (June 2007), incorporated herein by reference to Exhibit 10.102 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.59	+	First Amendment dated June 28, 2007 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of James Dale Underwood dated December 13, 2005 incorporated herein by reference to Exhibit 10.103 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.60	+	First Amendment dated June 28, 2007 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of James Underwood dated December 28, 2006, incorporated herein by reference to Exhibit 10.104 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.61		Amendment No. 7 and Agreement dated September 7, 2007 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender, and Natixis, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on September 11, 2007.
10.62		Securities Purchase Agreement dated November 2, 2007 among Cano Petroleum, Inc. and the Buyers listed therein, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on November 6, 2007.
10.63		Sponsorship Agreement dated December 16, 2004 between R.C. Boyd Enterprises, LLC and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.10 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 7, 2007.
10.64		First Amendment dated August 17, 2005 to Sponsorship Agreement between R.C. Boyd Enterprises, LLC and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.11 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 7, 2007.

Table of Contents

		Description

10.65		Second Amendment to the Sponsorship Agreement between R.C. Boyd Enterprises, LLC and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 7, 2007.
10.66		Sponsorship Agreement dated December 5, 2007 between Cano Petroleum, Inc. and R.C. Boyd Enterprises, LLC, incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-3 (File No. 333-148053) filed with the SEC on December 13, 2007.
10.67		Amendment No. 8 and Agreement dated January 16, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender and Natixis, incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 8, 2008.
10.68	+	First Amendment dated January 2, 2008 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of Donnie Dale Dent dated December 13, 2005, incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 8, 2008.
10.69	+	First Amendment dated January 2, 2008 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of Donnie Dale Dent dated December 28, 2006, incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 8, 2008.
10.70	+	Board of Directors compensation effective January 1, 2008, incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 8, 2008.
10.71	+	2008 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on February 21, 2008.
10.72	+	Summary of 2008 Cash Incentive Awards, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on February 21, 2008.
10.73	+	Summary of Acceleration of Vesting and Extension of Exercise Period for Resigning Directors (February 14, 2008), incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.74		$25,000,000 Subordinated Credit Agreement dated March 17, 2008 among Cano Petroleum, Inc. as Borrower, the Lenders Party Hereto from Time to Time as Lenders, and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.

Table of Contents

		Description

10.75		Subordinated Security Agreement dated March 17, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.76		Subordinated Pledge Agreement dated March 17, 2008 among Cano Petroleum, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc. and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.77		Subordinated Guaranty Agreement dated March 17, 2008 by Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., and W.O. Production Company, Ltd., in favor of UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.78		Amendment No. 9 and Agreement dated March 17, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.10 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.79		Consent Agreement dated February 21, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.11 to the Company's Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.80	+	First Amendment dated May 31, 2008 to Employment Agreement of S. Jeffrey Johnson dated January 1, 2006, incorporated herein by reference to Exhibit 10.84 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.81	+	Second Amendment dated May 31, 2008 to Employment Agreement of Morris B. Smith dated June 29, 2007, as amended, incorporated herein by reference to Exhibit 10.85 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.82	+	Third Amendment dated May 31, 2008 to Employment Agreement of Patrick M. McKinney dated June 29, 2007, as amended, incorporated herein by reference to Exhibit 10.86 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.83	+	Fourth Amendment dated May 31, 2008 to Employment Agreement of Michael J. Ricketts dated May 28, 2004, as amended, incorporated herein by reference to Exhibit 10.87 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.

Table of Contents

		Description

10.84	+	Employment Agreement of Phillip Feiner dated May 31, 2008, incorporated herein by reference to Exhibit 10.88 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.85	+	Employment Agreement of Benjamin Daitch dated June 23, 2008, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on June 24, 2008.
10.86	+	Restricted Stock Agreement of Benjamin Daitch dated June 23, 2008, incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on June 24, 2008.
10.87		Amendment No. 10 dated June 10, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.91 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.88		Consent and Amendment No. 11 dated June 27, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.92 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.89		Amendment No. 12 and Agreement dated effective June 30, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.93 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.90		Consent and Amendment No. 1 dated June 27, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.94 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.91		Amendment No. 2 dated effective June 30, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.95 to the Company's Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.92		Diamond Shamrock Refining Company, L.P. Crude Oil Purchase Contract dated August 6, 2001 between W.O. Operating Company, Ltd. and Diamond Shamrock Refining Company, L.P. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.96 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.

Table of Contents

Exhibit Number			Description

	10.93		Amendment 11 to Valero # 01-0838 dated June 12, 2006 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.97 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.94		Amendment 12 to Valero # 01-0838 dated August 23, 2006 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company, incorporated herein by reference to Exhibit 10.98 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.95		Amendment 13 to Valero # 01-0838 dated August 31, 2007 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.99 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.96		Amendment 14 to Valero # 01-0838 dated January 25, 2008 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.100 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.97		Amendment 15 to Valero # 01-0838 dated August 1, 2008 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.101 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.98		Amendment 16 to Valero # 01-0838 dated April 3, 2009 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company, incorporated herein by reference to Exhibit 10.102 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.99		Amendment 17 to Valero # 01-0838 dated May 1, 2009 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.103 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.100		Gas Purchase Agreement dated April 1, 2007 between Eagle Rock Field Services, L.P. and W.O. Operating Company, Ltd. and Pantwist, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.104 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.101		Letter Agreement dated March 25, 2009 Regarding Gas Purchase Agreement dated April 1, 2007 Eagle Rock Contract (#50038 Schafer) between Eagle Rock Energy Partners and W.O. Operating Company, Ltd. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.105 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.

Table of Contents

Exhibit Number			Description

	10.102		Letter Agreement dated April 30, 2009 Regarding Gas Purchase Agreement dated April 1, 2007 Eagle Rock Contract (#50038 Schafer) between Eagle Rock Energy Partners and W.O. Operating Company, Ltd., incorporated herein by reference to Exhibit 10.106 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009
	10.103		Summary of Oral Agreement for the Purchase of Crude Oil, between Ladder Energy Companies, Inc. and Coffeyville Resources Refinery and Marketing, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.107 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.104		Letter Agreement Regarding Crude Oil Purchase Agreement for Ladder Energy Operated Leases, dated January 15, 2009 between Ladder Energy Companies, Inc. and Coffeyville Resources Refinery and Marketing, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.108 to Amendment No. 2 to the Company's Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
	10.105		Letter Agreement Regarding Crude Oil Purchase Agreement for Ladder Energy Operated Leases, dated February 11, 2009 between Ladder Energy Companies, Inc. and Coffeyville Resources Refinery and Marketing, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.109 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.106		Letter Regarding Gas Purchase Contract No. PAM058500*, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.113 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.107		Letter Regarding Gas Purchase Contract No. BOR066300A, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.114 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.108		Letter Regarding Gas Purchase Contract No. BOR067500B, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.115 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.109		Letter Regarding Gas Purchase Contract No. BOR118000R, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.116 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.110		Letter Regarding Gas Purchase Contract No. BOR118100*, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.117 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.

Table of Contents

Exhibit Number			Description

	10.111		Letter Regarding Gas Purchase Contract No. BOR134200R, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.118 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.112		Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated February 1, 2000 between Sunoco, Inc. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.119 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.113		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 2, 2005 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.120 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.114		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 26, 2006 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.121 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.115		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 11, 2008 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.122 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.116		Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated March 1, 2004 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.123 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.117		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated December 4, 2006 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy, Inc. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.124 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
	10.118		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated February 16, 2009 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy, Inc. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.125 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.

Table of Contents

		Description

10.119		Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated April 2, 2009 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.126 to Amendment No. 2 to the Company's Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.120	+	Summary of 2009 Cash Incentive Awards, incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.121	+	Consulting Agreement dated October 1, 2008 between Cano Petroleum, Inc. and Morris B. Smith, incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on October 6, 2008.
10.122	+	Amendment to Employment Agreement of Phillip Feiner dated September 8, 2008, incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.123		Letter Agreement Regarding Payment of Prepayment Premium dated September 30, 2008 between Unionbancal Equities, Inc. and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.124		Consent and Amendment No. 13 dated September 30, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., Pantwist, LLC, Cano Petro of New Mexico, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd., Union Bank of California, N.A., as Administrative Agent, Issuing Lender and Lender and Natixis, incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.125		Letter Agreement dated November 19, 2008 between Union Bank of California, NA and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the SEC on November 20, 2008.
10.126		Letter Agreement dated November 19, 2008 between Unionbancal Equities, Inc. and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 10-Q filed with the SEC on November 20, 2008.
10.127		Temporary Waiver of Benefits dated October 28, 2008 between S. Jeffrey Johnson and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on July 8, 2009.
10.128	+	First Amendment to the Cano Petroleum, Inc. 2008 Annual Incentive Plan dated October 20, 2008, incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.129		$120,000,000 Amended and Restated Credit Agreement dated December 17, 2008 among Cano Petroleum, Inc. as Borrower, The Lenders Party Thereto From Time to Time as Lenders, and Union Bank of California, N.A. as Administrative Agent, incorporated herein by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.

Table of Contents

		Description

10.130		$25,000,000 Subordinated Credit Agreement dated December 17, 2008 among Cano Petroleum, Inc. as Borrower, The Lenders Party Thereto From Time to Time as Lenders, and UnionBanCal Equities, Inc. as Administrative Agent and as Issuing Lender, incorporated herein by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.131		Amended and Restated Guaranty Agreement dated December 17, 2008 by Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. in favor of Union Bank of California, N.A. as Administrative Agent, incorporated herein by reference to Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.132		Subordinated Guaranty Agreement dated December 17, 2008 by Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. in favor of UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.10 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.133		Amended and Restated Pledge Agreement dated December 17, 2008 among Cano Petroleum, Inc., WO Energy, Inc. and W.O. Energy of Nevada, Inc. and Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.11 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.134		Subordinated Pledge Agreement dated December 17, 2008 among Cano Petroleum, Inc., W.O. Energy, Inc. and W.O. Energy of Nevada, Inc. and UnionBanCal Equities, Inc., as Administrative Agent, incorporated herein by reference to Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.135		Amended and Restated Security Agreement dated December 17, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., W.O. Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. and Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.13 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.136		Subordinated Security Agreement dated December 17, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., W.O. Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. and UnionBanCal Equities, Inc., as Administrative Agent, incorporated herein by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.137	+	Second Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.

Table of Contents

		Description

10.138	+	First Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Ben Daitch, incorporated herein by reference to Exhibit 10.16 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.139	+	Fourth Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Patrick M. McKinney, incorporated herein by reference to Exhibit 10.17 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.140	+	Fifth Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Michael J. Ricketts, incorporated herein by reference to Exhibit 10.18 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.141	+	Second Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Phillip Feiner, incorporated herein by reference to Exhibit 10.19 to the Company's Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
12.1	*	Ratio of Earnings to Fixed Charges.
21.1	*	Subsidiaries of the Company.
23.1	*	Consent of Hein & Associates LLP.
23.2	*	Consent of Miller & Lents, Ltd., Independent Petroleum Engineers.
23.3	*	Consent of Forrest A. Garb & Associates, Inc., Independent Petroleum Engineers.
24.1	*	Power of Attorney (included on the signature page hereto).
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.
+: Management contract or compensatory plan, contract or arrangement.

Table of Contents

Item 8. Financial Statements and Supplementary Data.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Cano Petroleum, Inc.—Years Ended June 30, 2009, 2008 and 2007
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Changes in Stockholders' Equity		F-5
Consolidated Statements of Cash Flows		F-6
Notes to Consolidated Financial Statements		F-7

F-1

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
Cano Petroleum, Inc.
Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries (collectively, the "Company") as of June 30, 2009 and 2008, and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended June 30, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cano Petroleum, Inc. and subsidiaries as of June 30, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2009, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of June 30, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated September 28, 2009 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ HEIN & ASSOCIATES LLP

Dallas, Texas
September 28, 2009

F-2

Table of Contents

CANO PETROLEUM, INC.

CONSOLIDATED BALANCE SHEETS

				June 30,

In Thousands, Except Shares and Per Share Amounts				June 30,
In Thousands, Except Shares and Per Share Amounts				2009			2008
ASSETS				2009			2008
Current assets
	Cash and cash equivalents			$	392		$	697
	Accounts receivable				2,999			3,916
	Deferred tax assets				—			3,592
	Derivative assets				4,955			—
	Inventory and other current assets				810			642
	Assets held for sale (Note 8)				—			25,912

			Total current assets		9,156			34,759

Oil and gas properties, successful efforts method					288,857			247,930
Less accumulated depletion and depreciation					(40,208	)		(7,962	)

Net oil and gas properties					248,649			239,968

Fixed assets and other, net					3,240			2,096
Derivative assets					2,882			125
Goodwill					101			786

TOTAL ASSETS				$	264,028		$	277,734

		LIABILITIES, TEMPORARY EQUITY AND STOCKHOLDERS' EQUITY
Current liabilities
	Accounts payable			$	4,434		$	8,679
	Accrued liabilities				2,003			2,840
	Deferred tax liabilities				1,431			—
	Liabilities associated with discontinued operations (Note 8)				—			1,324
	Oil and gas sales payable				702			815
	Derivative liabilities				159			9,978
	Current portion of asset retirement obligations				86			345

			Total current liabilities		8,815			23,981
Long-term liabilities
	Long-term debt (Note 6)				55,700			73,500
	Asset retirement obligations				2,818			2,865
	Deferred litigation credit (Note 17)				—			6,000
	Derivative liabilities				—			16,390
	Deferred tax liabilities				22,831			26,062

			Total liabilities		90,164			148,798

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 and 44,474 shares issued at June 30, 2009 and 2008, respectively; liquidation preference at June 30, 2009 and 2008 of $26,987 and $48,353, respectively				25,405			45,086

Commitments and contingencies (Note 17)
Stockholders' equity
	Common stock, par value $.0001 per share; 100,000,000 authorized; 47,297,910 and 45,594,833 shares issued and outstanding, respectively, at June 30, 2009; and 40,523,168 and 39,254,874 shares issued and outstanding, respectively, at June 30, 2008				5			4
	Additional paid-in capital				189,526			121,831
	Accumulated deficit				(40,375	)		(37,414	)
	Treasury stock, at cost; 1,703,077 and 1,268,294 shares at June 30, 2009 and 2008, respectively				(697	)		(571	)

			Total stockholders' equity		148,459			83,850

TOTAL LIABILITIES, TEMPORARY EQUITY AND STOCKHOLDERS' EQUITY				$	264,028		$	277,734

See accompanying notes to these consolidated financial statements.

F-3

Table of Contents

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

			Years Ended June 30,

In Thousands, Except Per Share Data			2009			2008			2007
			2009			2008			2007
Operating Revenues:
	Crude oil sales		$	19,222		$	23,447		$	13,818
	Natural gas sales			5,875			10,886			6,833
	Other revenue			312			317			—

		Total operating revenues		25,409			34,650			20,651

Operating Expenses:
	Lease operating			18,842			13,273			8,733
	Production and ad valorem taxes			2,352			2,454			1,695
	General and administrative			19,156			14,859			12,635
	Impairment of long-lived assets (Note 14)			26,670			—			—
	Exploration expense (Note 9)			11,379			—			—
	Depletion and depreciation			5,720			3,903			3,202
	Accretion of discount on asset retirement obligations			305			204			131

		Total operating expenses		84,424			34,693			26,396

Loss from operations				(59,015	)		(43	)		(5,745	)
Other income (expense):
	Interest expense and other			(513	)		(761	)		(1,681	)
	Impairment of goodwill			(685	)		—			—
	Gain (loss) on derivatives (Notes 7 and 13)			43,790			(31,955	)		(847	)

		Total other income (expense)		42,592			(32,716	)		(2,528	)

Loss from continuing operations before income taxes				(16,423	)		(32,759	)		(8,273	)
Deferred income tax benefit (Note 16)				4,712			11,767			2,970

Loss from continuing operations				(11,711	)		(20,992	)		(5,303	)
Income from discontinued operations, net of related taxes of $6,441 in 2009, $1,953 in 2008 and $2,539 in 2007 (Note 8)				11,480			3,471			4,513

Net loss				(231	)		(17,521	)		(790	)
Preferred stock dividend				(2,730	)		(4,083	)		(3,169	)
Preferred stock repurchased for less than carrying amount				10,890			—			—

Net income (loss) applicable to common stock			$	7,929		$	(21,604	)	$	(3,959	)

Net income (loss) per share—basic and diluted
	Continuing operations		$	(0.08	)	$	(0.70	)	$	(0.28	)
	Discontinued operations			0.25			0.10			0.15

Net income (loss) per share—basic and diluted			$	0.17		$	(0.60	)	$	(0.13	)

Weighted average common shares outstanding
	Basic and Diluted			45,361			35,829			30,758

See accompanying notes to these consolidated financial statements.

F-4

Table of Contents

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

	Common Stock											Treasury Stock

	Common Stock					Additional Paid-in Capital			Accumulated Deficit			Treasury Stock
Dollar Amounts in Thousands	Shares			Amount		Additional Paid-in Capital			Accumulated Deficit			Shares		Amount			Total
Balance at July 1, 2006		26,987,941		$	2	$	53,055		$	(11,851	)		1,268,294	$	(571	)	$	40,635
Net proceeds from issuance of common shares and warrants		6,584,247			1		29,683			—			—		—			29,684
Issuance of common shares for acquisition of oil and gas properties		404,204			—		1,854			—			—		—			1,854
Stock-based compensation expense		(20,000	)		—		830			—			—		—			830
Forfeiture settlements		—			—		(183	)		—			—		—			(183	)
Preferred stock dividend		—			—		—			(3,169	)		—		—			(3,169	)
Net loss		—			—		—			(790	)		—		—			(790	)

Balance at June 30, 2007		33,956,392			3		85,239			(15,810	)		1,268,294		(571	)		68,861
Issuance of restricted stock		949,000			—		—			—			—		—			—
Stock-based compensation expense		—			—		2,905			—			—		—			2,905
Net proceeds from issuance of common shares from private placement and other		3,575,000			1		23,851			—			—		—			23,852
Net proceeds from issuance of common shares for warrants exercised		1,228,851			—		5,194			—			—		—			5,194
Common stock issued for preferred stock conversion		813,925			—		4,642			—			—		—			4,642
Preferred stock dividend		—			—		—			(4,083	)		—		—			(4,083	)
Net loss		—			—		—			(17,521	)		—		—			(17,521	)

Balance at June 30, 2008		40,523,168			4		121,831			(37,414	)		1,268,294		(571	)		83,850
Net proceeds from issuance of common shares on July 1, 2008		7,000,000			1		53,907			—			—		—			53,908
Forfeiture and surrender of restricted stock		(225,258	)		—		(261	)		—			—		—			(261	)
Stock-based compensation expense		—			—		3,159			—			—		—			3,159
Preferred stock dividend		—			—		—			(2,730	)		—		—			(2,730	)
Preferred stock repurchased for less than carrying amount		—			—		10,890			—			—		—			10,890
Shares returned to treasury stock from escrow related to acquisition of W.O. Energy of Nevada, Inc. (Note 17)		—			—		—			—			434,783		(126	)		(126	)
Net loss		—			—		—			(231	)		—		—			(231	)

Balance at June 30, 2009		47,297,910		$	5	$	189,526		$	(40,375	)		1,703,077	$	(697	)	$	148,459

See accompanying notes to these consolidated financial statements.

F-5

Table of Contents

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years Ended June 30,

In Thousands				2009			2008			2007
Cash flow from operating activities:				2009			2008			2007
	Net loss			$	(231	)	$	(17,521	)	$	(790	)
		Adjustments needed to reconcile net loss to net cash provided by (used in) operations:
			Unrealized loss (gain) on derivatives		(36,900	)		29,370			1,810
			Gain on sale of oil and gas properties		(19,246	)		—			(3,811	)
			Exploration expense		11,379			—			—
			Accretion of discount on asset retirement obligations		308			219			154
			Depletion and depreciation		5,735			5,009			4,425
			Impairment of oil and gas properties		30,186			—			—
			Impairment of goodwill		685			—			—
			Stock-based compensation expense		3,159			2,905			647
			Deferred income tax expense (benefit)		1,731			(9,901	)		(484	)
			Amortization of debt issuance costs and prepaid expenses		1,457			1,312			2,231
			Treasury stock		(126	)		—			—
	Changes in assets and liabilities relating to operations:
		Restricted cash			—			6,000			(6,000	)
		Accounts receivable			1,408			(844	)		(521	)
		Derivative assets			2,423			(291	)		(1,619	)
		Inventory and other current assets and liabilities			(1,244	)		(1,077	)		(794	)
		Accounts payable			(833	)		405			510
		Accrued liabilities			(6,271	)		1,139			1,132
		Oil and gas sales payable			(229	)		303			(232	)
		Deferred litigation credit			—			—			6,000

Net cash provided by (used in) operations					(6,609	)		17,028			2,658

Cash flow from investing activities:
	Additions to oil and gas properties				(56,202	)		(87,393	)		(46,324	)
	Proceeds from sale of equipment used in oil and gas activities				—			3,000			—
	Additions to fixed assets and other				(1,333	)		(358	)		(347	)
	Proceeds from sale of oil and gas properties				40,186			—			6,817

Net cash used in investing activities					(17,349	)		(84,751	)		(39,854	)

Cash flow from financing activities:
	Repayments of long-term debt				(128,500	)		(23,000	)		(68,750	)
	Borrowings of long-term debt				110,700			63,000			33,500
	Payments for debt issuance costs				(933	)		(507	)		(190	)
	Proceeds from issuance of common stock, net				53,908			29,046			29,684
	Proceeds from issuance of preferred stock, net				—			—			45,849
	Repurchases of preferred stock				(10,377	)		—			—
	Payment of deferred offering costs				—			(287	)		—
	Payment of preferred stock dividend				(1,145	)		(1,951	)		(1,423	)

Net cash provided by financing activities					23,653			66,301			38,670

Net decrease in cash and cash equivalents					(305	)		(1,422	)		1,474
Cash and cash equivalents at beginning of period					697			2,119			645

Cash and cash equivalents at end of period				$	392		$	697		$	2,119

Supplemental disclosure of noncash transactions:
	Payments of preferred stock dividend in kind			$	1,585		$	2,132		$	1,747
	Preferred stock repurchased for less than carrying amount			$	10,890		$	—		$	—
	Common stock issued for preferred stock conversion			$	—		$	4,642		$	—
	Common stock issued for acquisition of oil and gas properties			$	—		$	—		$	1,854
Supplemental disclosure of cash transactions:
	Cash paid during the period for interest			$	1,852		$	3,298		$	3,074

See accompanying notes to these consolidated financial statements.

F-6

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Cano Petroleum, Inc. (together with its direct and indirect wholly-owned subsidiaries, "Cano," "we," "us," or the "Company") is an independent crude oil and natural gas company based in Fort Worth, Texas. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery ("EOR") techniques at a low cost. We intend to convert these 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.

2. LIQUIDITY

At June 30, 2009, we had cash and cash equivalents of $0.4 million and working capital of $0.3 million. Our working capital balance included a $5.0 million derivative current asset and a $1.4 million deferred tax current liability. For the year ended June 30, 2009, we had net income applicable to common stock of $7.9 million and a loss from operations of $59.0 million, including a $26.7 million impairment of long-lived assets (see Note 14), $11.4 million of exploration expense (see Note 9) and $6.6 million of legal and settlement expenses in connection with the Panhandle fire litigation (see Note 17). For the year ended June 30, 2009, our cash used in operations of $6.6 million was negatively impacted by $10.7 million of settlement payments, net of reimbursements, related to the resolution of the Panhandle fire litigation.

We depend on our credit agreements, as described in Note 6, to fund a portion of our operating and capital needs. Under our senior credit agreement, the initial and current borrowing base, based upon our proved reserves, is $60.0 million. At June 30, 2009, our remaining available borrowing capacity under the senior credit agreement was $19.3 million, and at September 28, 2009, our remaining borrowing capacity was $13.8 million. Pursuant to the terms of our senior credit agreement, 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.

At June 30, 2009, we were in compliance with the debt covenants contained in each of our credit agreements. The 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 8). Based upon our six month operating results through June 30, 2009, we may not be in compliance with all of our financial covenants when we reach the twelve-month period ending December 31, 2009. If a combination of increased production, rising commodity prices, changes in our capital structure 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.

We have taken, and are considering taking, actions to ensure the aforementioned covenant compliance and sufficient liquidity to meet our obligations for the twelve months ending June 30, 2010, which includes funding our capital expenditure budget of $13.9 million. Actions we have taken during the six-month period ended June 30, 2009 to improve liquidity include: negotiating lower service rates with vendors, employee workforce reductions and shutting-in uneconomic wells. As discussed in Note 7, we have derivative contracts in place to protect us from falling crude oil and natural gas commodity prices on a portion of our production (through December 2012) and rising interest rates related to a portion of our outstanding debt (through January 2012). We are also considering credit and capital markets alternatives.

F-7

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. LIQUIDITY (Continued)

During each year of our prior five years in existence, we have successfully accessed the credit and capital markets to fund our operations and capital needs.

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) debt available under our credit agreements and (iv) our ability to access the equity markets, provide sufficient means to conduct our operations, meet our contractual obligations and undertake our capital expenditure program for the twelve months ending June 30, 2010. To the extent that cash on hand as of June 30, 2009, cash flow generated by operations subsequent to June 30, 2009 and borrowings under our credit agreements are insufficient to fund our operating cash flow requirements and our capital expenditure plans, we will need to (i) raise capital through the issuance of debt or equity securities (ii) refinance our existing credit arrangements, (iii) divest oil and gas property assets, (iv) reduce operating and capital expenditures, and (v) pursue strategic alternatives. There can be no assurance that we will be successful in refinancing our credit arrangements or raising capital through the issuance of our debt or equity securities.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation and Use of Estimates

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

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.

Oil and Gas Properties and Equipment

F-8

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

found. If proved reserves are found, the deferred costs are capitalized as part of the wells and related equipment and facilities. If no proved reserves are found, the deferred costs are charged to expense. All development activity costs are capitalized. We are primarily engaged in the development and acquisition of crude oil and natural gas properties. Our activities are considered development where existing proved reserves are identified prior to commencement of the project and are considered exploration if there are no proved reserves at the beginning of such project. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisition and development activities and deferred exploratory drilling costs. Capitalized overhead costs that directly relate to our drilling and development activities were $1.1 million and $0.8 million, for the years ended June 30, 2009 and 2008, respectively. We recorded capitalized interest costs of $1.4 million and $2.5 million for the years ended June 30, 2009 and 2008, respectively.

Depreciation and depletion of producing properties are computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Our unit-of-production amortization rates are revised prospectively on a quarterly basis based on updated engineering information for our proved developed reserves. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until impairment occurs. As of June 30, 2009 and 2008, capitalized costs related to waterflood and alkaline-surfactant-polymer ("ASP") projects that were in process and not subject to depletion amounted to $49.4 million and $47.6 million, respectively, of which $4.8 million and $13.3 million, respectively, were deferred costs related to drilling and equipping exploratory wells as discussed in Note 9 below.

Asset Retirement Obligation

F-9

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Goodwill

The amount paid for certain acquisitions in excess of the fair value of the net assets acquired has been recorded as goodwill in the consolidated balance sheets. Goodwill is not amortized, but is assessed for impairment annually or whenever conditions would indicate impairment may exist. The goodwill impairment analysis is evaluated at the subsidiary level as part of the impairment analysis performed on oil and gas properties, as previously discussed.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less. Excess cash funds are generally invested in U.S. government-backed securities. At times, we maintain deposit balances in excess of Federal Deposit Insurance Corporation insurance limits.

Accounts Receivable

Accounts receivable principally consist of crude oil and natural gas sales proceeds receivable and are typically collected within 35 days from the end of the month in which the related quantities are produced. We require no collateral for such receivables, nor do we charge interest on past due balances. We periodically review accounts receivable for collectability and reduce the carrying amount of the accounts receivable by an allowance. No such allowance was recorded at June 30, 2009 or 2008. As of June 30, 2009, our accounts receivable were primarily with independent purchasers of our crude oil and natural gas production. At June 30, 2009, we had balances due from three customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These three customers accounted for 41% (Valero Marketing Supply Co.), 19% (Coffeyville Resources Refinery and Marketing, LLC) and 18% (Plains Marketing, LP) of our accounts receivable, respectively.

At June 30, 2008, we had balances due from five customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These five customers accounted for 29% (Valero Marketing Supply Co.), 17% (Coffeyville Resources Refinery and Marketing, LLC), 15% (Eagle Rock Field Services, LP), 14% (DCP Midstream, LP) and 13% (Plains Marketing, LP) of our accounts receivable, respectively.

In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative purchasers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost purchasers. We would not expect the loss of any single purchaser to have a long-term material adverse effect on our operations, though we may experience a short-term decrease in our revenues as we make arrangements for alternative purchasers. However, the loss of a single purchaser could potentially reduce the competition for our crude oil and natural gas production, which could negatively impact the prices we receive.

Revenue Recognition

Our revenue recognition is based on the sales method. We do not have imbalances for natural gas sales. We recognize revenue when crude oil and natural gas quantities are delivered to or collected by

F-10

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

	Year Ended June 30,

	2009			2008			2007
Valero Marketing Supply Co.		32	%		33	%		36	%
Coffeeville Resources Refinery and Marketing, LLC		18	%		15	%		16	%
Plains Marketing, LP		15	%		*			*
Eagle Rock Field Services, LP		13	%		18	%		18	%
DCP Midstream, LP		10	%		14	%		17	%

*: Less than 10% of operating revenue

Oil and Gas Sales Payable

Our accounts receivable includes amounts that we collect from the purchasers of our crude oil and natural gas sales on behalf of us, and certain working interest and royalty owners. The portion of accounts receivable that pertains to us is recognized as operating revenue. The portion that pertains to certain working interest and royalty owners are recorded as oil and gas sales payable.

Inventory

Our inventory consists of unsold barrels of crude oil remaining in our storage tanks at the end of the period. We value these crude oil barrels based on the lower of market or our average production cost.

Income Taxes

Deferred tax assets or liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities. These balances are measured using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

F-11

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

As of June 30, 2008, the adoption of FIN 48, "Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109" ("FIN 48") did not materially affect our operating results, financial position, or cash flows. As of June 30, 2009, we have not recorded any accruals for uncertain tax positions. We are not involved in any examinations by the Internal Revenue Service. For Texas, Oklahoma, New Mexico and U.S. federal purposes, the review of our income tax returns is open for examination by the related taxing authorities for the tax years of 2004 through 2008.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, unless otherwise stated, as of June 30, 2009 and 2008. The carrying amount of long-term debt approximates market value due to the use of market interest rates.

Net Income (Loss) per Common Share

Diluted net income (loss) per common share is computed in the same manner as basic net income (loss) per common share, but also considers the effect of common stock shares underlying the following:

	Year Ended June 30,

	2009		2008		2007
Stock options (Note 10)		1,400,002		1,084,051		801,513
Warrants		—		—		1,646,061
Preferred Stock (Note 5)		4,147,652		7,734,609		8,541,913
Paid-in-kind dividends ("PIK") (Note 5)		545,773		674,569		303,813
Non-vested restricted shares (Note 11)		480,000		1,005,000		95,000

The shares of common stock underlying the stock options, warrants, Preferred Stock, PIK dividends and non-vested restricted shares, as shown in the preceding table, are not included in weighted average shares outstanding for the years ended June 30, 2009, 2008 or 2007 as their effects would be anti-dilutive.

Stock-Based Compensation Expense

We account for share-based payment arrangements with employees and directors at their grant-date fair value and record the related expense over their respective service periods. The value of stock-based compensation is impacted by our stock price, which has been highly volatile, and items that require management's judgment, such as expected lives and forfeiture rates.

Derivatives

We are required to hedge a portion of our production at specified prices for oil and natural gas under our senior and subordinated credit agreements, as discussed in Note 6. The purpose of the derivatives is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect our cash flows which support our annual capital expenditure plans. We have entered into commodity derivatives that involve "costless collars" for our crude oil and natural gas sales. These

F-12

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets based upon their respective fair values. We have entered into an interest rate basis swap contract to reduce our exposure to future interest rate increases.

Comprehensive Income

We had no elements of comprehensive income other than net loss for the years ended June 30, 2009, 2008 and 2007.

New Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141 (revised 2007), Business Combinations ("SFAS No. 141R"). Among other things, SFAS No. 141R 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. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We adopted SFAS No. 141R on July 1, 2009. This standard will change our accounting treatment for prospective business combinations.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 ("SFAS No. 160"). SFAS No. 160 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. We do not expect the adoption of this statement will have a material impact on our financial position, results of operations or cash flows.

F-13

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

the accounting for derivative instruments and related hedged items under SFAS No. 133; and how derivative instruments and related hedged items affect the company's financial position, financial performance and cash flows. We adopted SFAS No. 161 on July 1, 2009. We do not expect the adoption of this statement to have a material impact on our financial position, results of operations or cash flows.

In December 2008, the FASB issued EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock ("EITF 07-5"). EITF 07-5 affects companies that have provisions in their securities purchase agreements (for warrants and convertible instruments) that reset issuance/conversion prices based upon new issuances by companies at prices below the exercise 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 under SFAS No. 133. Subject to certain exceptions, our Preferred Stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. EITF is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted EITF 07-5 on July 1, 2009. We do not expect the adoption of this statement to have a material impact on our financial position, results of operations or cash flows. Had we adopted EITF 07-5 on June 30, 2009, we estimate that we would have reduced our temporary equity by approximately $0.7 million to $1.0 million and recorded a derivative liability for the same $0.7 million to $1.0 million amount, which would be marked-to-market for future reporting periods.

F-14

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

4. COMMON STOCK FINANCINGS

Common Stock Issuance Completed July 1, 2008

On July 1, 2008, we completed the sale of 7.0 million shares of our common stock through an underwritten offering at a price of $8.00 per share ($7.75 net to us) resulting in net proceeds of approximately $53.9 million after underwriting discounts, commissions and expenses. We used the net proceeds from the offering to pay down debt. We subsequently made borrowings against our borrowing base in order to finance our development activities in certain core areas such as the Panhandle and Cato Properties and general corporate purposes.

Private Placement

On November 7, 2007, we sold 3.5 million shares of our common stock in a private placement at a price of $7.15 per share for net proceeds of $23.4 million after deducting issuance costs of $1.6 million. The net proceeds were used to pay down long-term debt due under our senior credit agreement.

In connection with the private placement, we entered into a registration rights agreement with the purchasers in such private placement which required us to file a registration statement within a certain period of time and have it declared effective within a certain period of time. We met both of these deadlines. However, if we are not able to maintain the effectiveness of the registration statement, subject to certain limitations, we will have to pay 1.0% of the aggregate purchase price of the securities purchased in the private placement on the first day of such initial maintenance failure and on each 30^th day after the day of such initial maintenance failure (prorated for periods totaling less than 30 days), with the maximum aggregate registration delay payments being 10% of the aggregate purchase price. We do not believe it is probable we will incur any penalties under this provision and accordingly have not accrued any loss.

5. PREFERRED STOCK

On September 6, 2006, we sold $49.1 million of Preferred Stock. We were required to file a registration statement on Form S-1 with the Securities and Exchange Commission (the "SEC") registering the resale of the common shares underlying the Preferred Stock, which was filed on October 13, 2006 and was declared effective on January 4, 2007. On April 9, 2007, we also filed to register these same common shares on a registration statement on Form S-3, which was declared effective on April 19, 2007. We are required to maintain the effectiveness of the registration statement until such common shares may be resold pursuant to Rule 144(k) under the Securities Act of 1933, as amended, or all such common shares have been resold subject to certain exceptions, and if the

F-15

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. PREFERRED STOCK (Continued)

effectiveness is not maintained, then we must pay 1.5% of the gross proceeds and an additional 1.5% for every 30 days it is not maintained. The maximum aggregate of all registration delay payments is 10% of the gross proceeds from the September 2006 offering. We do not believe it is probable we will incur any penalties under this provision and accordingly have not accrued any loss.

The Preferred Stock has a 7.875% dividend and features a paid-in-kind ("PIK") provision that allows the investor, at its option, to receive additional shares of common stock upon conversion for the dividend in lieu of a cash dividend payment. Once the investor has chosen the PIK or cash distribution, all future distribution will follow the same choice. As of June 30, 2009, approximately 59% of the Preferred Stock dividends were PIK. The Preferred Stock is convertible at the holder's option to common stock at a price of $5.75 per share. If any Preferred Stock remains outstanding on September 6, 2011, we are required to redeem the Preferred Stock for a redemption amount in cash equal to the stated value of the Preferred Stock, plus accrued dividends and PIK dividends. The issuance of Preferred Stock is accounted for as temporary equity since the holder can request redemption for cash under certain circumstances.

Pursuant to the terms of the Preferred Stock and subject to certain exceptions, if we issue or sell common stock at a price less than the conversion price (currently $5.75 per share) in effect immediately prior to such issuance or sale, the conversion price shall be reduced. If such an issuance is made, the conversion price will be lowered to the weighted average price of (x) the total common shares outstanding prior to said issuance multiplied by $5.75 and (y) the new shares issued at the new issuance price. The above described adjustment is not triggered by issuances or sales involving the following: (i) shares issued in connection with an employee benefit plan; (ii) shares issued upon conversion of our Preferred Stock; (iii) shares issued in connection with a firm commitment underwritten public offering with gross proceeds in excess of $50,000,000; (iv) shares issued in connection with any strategic acquisition or transaction; (v) shares issued in connection with any options or convertible securities that were outstanding on August 25, 2006; or (vi) shares issued in connection with any stock split, stock dividend, recapitalization or similar transaction.

Each holder of Preferred Stock is entitled to the whole number of votes equal to the number of shares of common stock issuable upon conversion. The Preferred Stock shall vote as a class with the holders of the common stock as if they were a single class of securities upon any matter submitted to the vote of the stockholders except those matters required by law or the terms of the Preferred Stock to be submitted to a class vote of the holders of the Preferred Stock, in which case the holders of the Preferred Stock only shall vote as a separate class.

Upon a voluntary or involuntary liquidation, dissolution or winding up of Cano or such subsidiaries of Cano the assets of which constitute all or substantially all of the assets of the business of Cano and its subsidiaries taken as a whole, the holders of our Preferred Stock shall be entitled to receive an amount per share equal to $1,000 plus dividends owed on such share prior to any payments being made to any class of capital stock ranking junior on liquidation to the Preferred Stock.

At June 30, 2009, 26,987 shares of Series D Convertible Preferred Stock remain outstanding (including 3,138 shares from PIK dividends). At June 30, 2008, there were 48,353 shares of our Preferred Stock outstanding, including 3,879 shares from PIK dividends. During November and December 2008, we repurchased 22,948 shares of Series D Convertible Preferred Stock, including accrued dividends and 2,323 shares from PIK dividends for approximately $10.4 million.

F-16

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. PREFERRED STOCK (Continued)

For the year ended June 30, 2009, the preferred dividend was $2.7 million, of which $1.6 million were PIK dividends. For the twelve months ended June 30, 2008, the preferred dividend was $4.1 million, of which $2.1 million were PIK dividends.

At June 30, 2009, the Preferred Stock and cumulative PIK dividends were convertible into 4,147,652 and 545,773 shares, respectively, of our common stock at a conversion price of $5.75 per share.

6. LONG-TERM DEBT

Senior Credit Agreement

F-17

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. LONG-TERM DEBT (Continued)

The ARCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBNA, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBNA, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.

Subordinated Credit Agreement

F-18

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. LONG-TERM DEBT (Continued)

(vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.

7. DERIVATIVES

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

Commodity Derivatives

Pursuant to our senior and subordinated credit agreements discussed in Note 6, we are required to maintain our existing commodity derivative contracts, all of which have UBNA as our counterparty. 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 June 30, 2009, we maintained the following commodity derivative contracts:

Time Period	Floor Oil Price		Ceiling Oil Price			Floor Gas Price		Ceiling Gas Price

7/1/09 - 12/31/09	$	80.00	$	110.90	367	$	7.75	$	10.60	1,667	644
7/1/09 - 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."

During October 2008, we sold certain uncovered "floor price" commodity derivative contracts for the period July 2010 to December 2010 for $0.6 million to our counterparty and realized a gain of $0.1 million. During November 2008, we sold all remaining uncovered "floor price" commodity derivative contracts for the period November 2008 through June 2010 for $2.6 million to our counterparty and realized a gain of $0.6 million.

Time Period	Fixed Oil Price

4/1/11 - 12/31/11	$	75.90	700
1/1/12 - 12/31/12	$	77.25	700

F-19

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. DERIVATIVES (Continued)

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. 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. We do not designate this interest rate swap contract as either a cash flow or fair value hedge.

Financial Statement Impact

During the years ended June 30, 2009, 2008 and 2007, respectively, the gain (loss) on derivatives reported in our consolidated statements of operations is summarized as follows:

	Year Ended June 30,

	2009			2008			2007
Settlements received/accrued	$	6,840		$	504		$	963
Settlements received—sale of "floor price" contracts		653			—			—
Settlements paid/accrued		(603	)		(3,089	)		—

Realized gain (loss) on derivatives		6,890			(2,585	)		963
Unrealized gain (loss) on commodity derivatives		36,849			(29,370	)		(1,810	)
Unrealized gain on interest rate swap		51			—			—

Gain (loss) on derivatives	$	43,790		$	(31,955	)	$	(847	)

The realized gain (loss) on derivatives consists of actual cash settlements under our commodity collars and interest rate swap derivatives during the respective periods, and the sale of "floor price" commodity derivative contracts during October and November 2008. 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 were quarterly payments to our counterparty since the actual three- month LIBOR interest rate was lower than the fixed 1.73% rate we pay to the counterparty. The cash flows relating to the derivative instrument settlements that are due, but not cash settled are reflected in operating activities on our consolidated statements of cash flows as changes to current liabilities. At June 30, 2009, we had recorded a $0.6 million receivable from our counterparty included in accounts receivable on our consolidated balance sheet. At June 30, 2008, we had recorded a $1.2 million payable to our counterparty included in accounts payable on our consolidated balance sheet.

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 in Note 13. We compared our valuation to our counterparties' independently derived valuation to further validate our mark-to-market valuation. During the year ended June 30, 2009, we recognized an unrealized gain on commodity derivatives in our consolidated statements of operations amounting to $36.8 million. During the years ended June 30,

F-20

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. DERIVATIVES (Continued)

2008 and 2007, we recognized an unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $29.4 million and $1.8 million, respectively.

The unrealized gain 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 in Note 13. We compared our valuation to our counterparties' independently derived valuation to further validate our mark-to-market valuation. During the year ended June 30, 2009, we recognized an unrealized gain on interest rate swaps in our consolidated statements of operations amounting to $0.1 million. Since we did not implement the interest rate swap until January 2009, we did not have unrealized gain or loss on the interest rate swap during the years ended June 30, 2008 and 2007.

As of June 30, 2009, we had aggregate derivative commodity assets of $7.6 million and a net derivative asset for the interest rate swap of $0.1 million. These amounts are based on our mark-to-market valuation of these derivatives at June 30, 2009 and may not be indicative of actual future cash settlements.

8. 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. At October 1, 2008, we recorded a pre-tax gain associated with the sale, exclusive of discontinued operating income, of approximately $19.2 million ($12.2 million after-tax). All current tax liabilities associated with such gain were offset by existing net operating losses. We used the entire $42.1 million net cash proceeds received from the transaction and cash on hand to pay down amounts outstanding under our senior credit agreement on October 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.

On June 11, 2007, pursuant to the terms of an Agreement for Purchase and Sale, we sold our interests in the Rich Valley Properties located in Oklahoma and Kansas to Anadarko Minerals, Inc. for net proceeds of $6.8 million. The agreement had an effective date of April 1, 2007. The funds received were used to reduce long-term debt.

F-21

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DISCONTINUED OPERATIONS (Continued)

The operating results of Pantwist, LLC, Corsicana Properties and the Rich Valley Properties for the years ended June 30, 2009, 2008 and 2007 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below.

			For the Year Ended June 30,

In Thousands			2009			2008			2007
Operating Revenues:
	Crude oil sales		$	1,321		$	4,461		$	3,715
	Natural gas sales			1,757			5,552			5,397

		Total operating revenues		3,078			10,013			9,112

Operating Expenses:
	Lease operating			638			2,248			2,700
	Production and ad valorem taxes			197			900			869
	General and administrative			—			24			280
	Impairment of long-lived assets			3,516			—			—
	Depletion and depreciation			15			1,106			1,223
	Accretion of discount on asset retirement obligations			3			15			23
	Interest expense, net			34			220			776

		Total operating expenses		4,403			4,513			5,871

Gain (loss) on sale of properties				19,246			(76	)		3,811

Income before income taxes				17,921			5,424			7,052
Income tax provision				(6,441	)		(1,953	)		(2,539	)

Income from discontinued operations			$	11,480		$	3,471		$	4,513

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

At June 30, 2008, on our consolidated balance sheet, the assets of Pantwist, LLC and assets relating to the Corsicana Properties are classified as assets held for sale and the liabilities are classified as liabilities associated with discontinued operations.

9. COSTS INCURRED FOR DRILLING AND EQUIPPING EXPLORATORY WELLS USING SECONDARY AND TERTIARY TECHNOLOGY

As part of our growth strategy, we incur costs associated with secondary and tertiary techniques that involve drilling and equipping exploratory wells. This occurs within reservoirs for which we already have proved developed reserves recorded from existing primary or secondary development; however, there are no proved reserves for subsequent secondary or tertiary activities. Secondary and tertiary costs for drilling and equipping wells include converting primary production wells to injection wells, installation of injection facilities, and injecting materials. When conducting secondary and tertiary drilling and equipping activities, we defer drilling and equipping costs associated with these exploratory wells pending a determination of whether proved reserves are found. If proved reserves are not found, all of the costs associated with the project are recorded as exploration expense in the period in which such determination is made. If proved reserves are found, the drilling and equipping costs incurred in

F-22

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. COSTS INCURRED FOR DRILLING AND EQUIPPING EXPLORATORY WELLS USING SECONDARY AND TERTIARY TECHNOLOGY (Continued)

the project are added to the depletion base and depreciated using the units of production method based over the production life of the associated proved developed reserves.

At June 30, 2009, there is one tertiary project (the Nowata ASP flood), that is pending the determination of whether proved reserves have been found. Secondary and tertiary projects typically take longer to complete than drilling primary production wells, and as a result, the period during which exploratory drilling costs are deferred is longer. The table below summarizes the drilling and equipping costs incurred and deferred related to secondary and tertiary projects at June 30, 2009, 2008 and 2007, that are pending the determination of whether proved reserves have been found.

	June 30,

In Thousands	2009		2008		2007
Secondary—Duke Sands	$	—	$	9,857	$	5,824
Tertiary—Nowata ASP Pilot		4,849		3,216		814

Total Costs	$	4,849	$	13,073	$	6,638

The following table provides an aging of deferred exploratory well costs based on the date the project was initiated (prior to determination of success).

	June 30,

In Thousands	2009		2008		2007
Capitalized exploratory well costs that have been capitalized period of one year or less	$	1,633	$	6,435	$	5,420
Capitalized exploratory well costs that have been capitalized period of one to three years		3,216		6,638		1,218

Balance at June 30	$	4,849	$	13,073	$	6,638

Number of projects that have exploratory well costs that have been capitalized for a period of one to three years		1		2		2

Our secondary and tertiary projects are evaluated to determine whether they have found proved reserves when the project is substantially complete. We consider a secondary or tertiary project to be substantially complete when the amount of material injected reaches our target pore volume injection ("PVI") percentage determined necessary to stimulate response. Our two projects are the Duke Sands waterflood at our Desdemona Properties and the ASP tertiary recovery pilot project at the Nowata Properties. As of June 30, 2009, the Nowata ASP project was not complete, and as such, all of the associated drilling and equipping costs to date have been deferred. The Nowata ASP project is expected to take an additional three to six months before the final polymer flush is complete and the response can be evaluated. It is anticipated that an additional $0.3 million will be required to complete this project.

Regarding the Duke Sands project, the primary source of water for this waterflood project had been derived from our Barnett Shale production. Since we have shut-in our Barnett Shale natural gas production due to uneconomic natural gas commodity prices, as previously discussed, we no longer have an economic source of water to continue flooding the Duke Sands. Therefore, our rate of water

F-23

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. COSTS INCURRED FOR DRILLING AND EQUIPPING EXPLORATORY WELLS USING SECONDARY AND TERTIARY TECHNOLOGY (Continued)

injection has been reduced to a point where we cannot consider the waterflood active. We have recorded exploration expense of $11.4 million for the year ended June 30, 2009. For the years ended June 30, 2009 and 2008, we incurred no costs associated with exploration expenses such as geological and geophysical expenses and delay rentals.

The following table reflects the net change in deferred exploratory project costs during fiscal years 2009, 2008 and 2007:

		Year ended June 30,

In Thousands		2009			2008		2007
Balance at July 1		$	13,073		$	6,638	$	1,218
	Additions pending the determination of proved reserves		3,155			6,435		5,420
	Deferred exploratory well costs charged to expense		(11,379	)		—		—

Balance at June 30		$	4,849		$	13,073	$	6,638

10. STOCK OPTIONS

We have granted stock options to our employees and outside directors as discussed below.

Prior to our 2005 Long-Term Incentive Plan

On December 16, 2004, we issued stock options for 50,000 shares of our common stock to Gerald Haddock, a former member of our board of directors, in exchange for certain financial and management consulting services at an exercise price of $4.00 per share. The options are exercisable at any time, in whole or in part, during the life of the option which expires on June 15, 2015.

On April 1, 2005, we adopted the 2005 Directors' Stock Option Plan ("Plan"). On April 1, 2005, pursuant to the Plan, we granted stock options to our five non-employee directors to each purchase 25,000 shares of common stock at an exercise price of $4.13 per share. The options vested on April 1, 2006, and expire on April 1, 2015. During the year ended June 30, 2008, 50,000 options shares were exercised, 25,000 option shares were forfeited and the outstanding vested options totaled 50,000 shares.

2005 Long-Term Incentive Plan

Our 2005 Long-Term Incentive Plan (the "2005 LTIP"), as approved by our stockholders, authorized the issuance of up to 3,500,000 shares of our common stock to key employees, consultants and outside directors of our company and subsidiaries. The 2005 LTIP stipulates that for any calendar year (i) the maximum number of stock options or stock appreciation rights that any Executive Officer (as defined in the Plan) can receive is 300,000 shares of common stock, (ii) the maximum number of shares relating to restricted stock, restricted stock units, performance awards or other awards that are subject to the attainment of performance goals that any Executive Officer can receive is 300,000 shares of common stock; and (iii) the maximum number of shares relating to all awards that an Executive Officer can receive is 300,000 shares. The 2005 LTIP permits the grant of incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, dividend equivalent rights and other awards, whether granted singly, in

F-24

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCK OPTIONS (Continued)

combination or in tandem. The 2005 LTIP terminates on December 7, 2015; however, awards granted before that date will continue to be effective in accordance with their terms and conditions.

Stock option awards are generally granted with an exercise price equal to our market price at the date of grant and have 10-year contractual terms. Stock option awards to employees generally vest over three years of continuous service. Stock option awards to directors generally vest immediately or in one year. On June 28, 2007, we resolved that upon the resignation of any current member of the Board of Directors who is in good standing on the date of resignation, such member's unvested stock options shall be vested and shall have the exercise period for all options extended to twenty-four months after the date of resignation. The grant-date fair value of director options for which vesting was accelerated during the year ended June 30, 2008 amounted to approximately $31,000. Such amount is included in general and administrative expense on our consolidated statements of operations. There were no options for which vesting was accelerated during the years ended June 30, 2009 or 2007.

A summary of options we granted during the years ended June 30, 2009, 2008 and 2007 are as follows:

			Weighted Average Exercise Price

Outstanding at July 1, 2006	577,185		$	5.66
Options granted	564,303		$	5.37
Options forfeited or expired	(314,975	)	$	6.21
Options exercised	(25,000	)	$	4.13

Outstanding at June 30, 2007	801,513		$	5.29
Options granted	398,941		$	6.48
Options forfeited or expired	(41,403	)	$	5.76
Options exercised	(75,000	)	$	5.28

Outstanding at June 30, 2008	1,084,051		$	5.71
Options granted	577,900		$	1.87
Options forfeited or expired	(261,949	)	$	3.93

Outstanding at June 30, 2009	1,400,002		$	4.42

F-25

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCK OPTIONS (Continued)

The following is a summary of stock options outstanding at June 30, 2009:

Exercise Price

$	0.43	276,346	9.41	200,675
$	0.60	7,600	9.34	—
$	0.70	3,500	9.86	—
$	3.19	6,100	9.20	—
$	3.27	3,000	9.15	—
$	3.98	161,646	9.08	62,175
$	4.00	50,000	5.47	50,000
$	4.13	25,000	5.76	25,000
$	4.73	61,803	7.77	61,803
$	5.15	81,435	6.98	81,435
$	5.42	276,667	7.50	213,333
$	5.75	163,400	8.65	23,999
$	5.95	10,000	8.21	—
$	6.15	32,800	8.01	—
$	6.30	75,000	6.46	75,000
$	7.25	150,000	8.46	150,000
$	7.47	15,705	8.42	—

$	4.42	1,400,002	8.17	943,420

Based on our $0.95 stock price at June 30, 2009, the intrinsic value of the "in-the-money" options was $0.1 million for each of the outstanding options and the exercisable options.

Total options exercisable at June 30, 2009 amounted to 943,420 shares and had a weighted average exercise price of $4.46. Upon exercise, we issue the full amount of shares exercisable per the terms of the options from new shares. We have no plans to repurchase those shares in the future.

The following is a summary of options exercisable at June 30, 2009, 2008 and 2007:

		Weighted Average Exercise Price

June 30, 2009	943,420	$	4.46
June 30, 2008	561,803	$	5.75
June 30, 2007	250,000	$	5.19

The fair value of each stock option is estimated on the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on historical volatility of our common stock. We use historical data to estimate option exercise and employee termination within the valuation model. The expected lives of options granted represent the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the five-year U.S. Treasury yield curve in effect at the time of grant. The expected dividend yield reflects our intent not to pay dividends on our common stock during the contractual periods.

F-26

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCK OPTIONS (Continued)

The fair values of options granted along with the factors used to calculate the fair values of those options are summarized in the table below:

	Years Ended June 30,

	2009			2008			2007
No. of shares		577,900			398,941			564,303
Risk free interest rate		2.15-3.39	%		2.93-4.07	%		4.56-4.91	%
Expected life		5 years			5 years			4 years
Expected volatility		56.3-90.1	%		49.1-49.7	%		50.5-53.4	%
Expected dividend yield		0	%		0	%		0	%
Weighted average grant date fair value—exercise prices equal to market value on grant date	$	0.99		$	3.18		$	2.64
Weighted average grant date fair value—exercise prices greater than market value on grant date		—		$	—		$	2.44
Weighted average grant date fair value—exercise prices less than market value on grant date	$	—		$	—		$	—

For the years ended June 30, 2009, 2008 and 2007, we have recorded a charge to stock compensation expense of $0.7 million, $1.2 million and $0.6 million, respectively, for the estimated fair value of the options granted to our directors and employees. As of June 30, 2009, total compensation cost related to non-vested options awards not yet recognized amounted to $0.5 million, and we expect to recognize that amount over the remaining requisite service periods of the related awards of up to three years.

11. DEFERRED COMPENSATION

During June 2006, 140,000 restricted shares were issued to key employees from our 2005 LTIP, previously discussed in Note 10. On July 2, 2007, we granted our executive officers restricted stock for services provided during the year ended June 30, 2007 totaling 395,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of July 2, 2007.

On May 12, 2008, we granted our executive officers restricted stock for services provided during the year ended June 30, 2008 totaling 460,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of May 12, 2008. On June 23, 2008, in connection with his hiring, we granted an executive officer restricted stock totaling 100,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of June 23, 2008.

F-27

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEFERRED COMPENSATION (Continued)

A summary of non-vested restricted share activity for the three years ended June 30, 2009, 2008 and 2007 is as follows:

			Weighted Average Grant- Date Fair Value		Fair Value $000s

Non-vested restricted shares at July 1, 2006	140,000		$	5.62	$	787
Shares granted	5,000			5.03		25
Shares forfeited and surrendered	(50,000	)		5.62		(281	)

Non-vested restricted shares at June 30, 2007	95,000			5.59		531
Shares granted	955,000			6.86		6,552
Shares vested	(45,000	)		5.55		(250	)
Shares forfeited and surrendered	—			—		—

Non-vested restricted shares at June 30, 2008	1,005,000			6.80		6,833
Shares granted	—			—		—
Shares vested	(394,376	)		6.61		(2,605	)
Shares forfeited and surrendered	(130,624	)		6.76		(884	)

Non-vested restricted shares at June 30, 2009	480,000		$	6.97	$	3,344

The restricted shares will vest to the individual employees based on future years of service ranging from one to three years depending on the life of the award agreement. The fair value is based on our actual stock price on the date of grant multiplied by the number of restricted shares granted. As of June 30, 2009, the value of non-vested restricted shares amounted to $3.3 million. In accordance with SFAS No. 123(R), for the years ended June 30, 2009, 2008 and 2007, we have expensed $2.4 million, $1.7 million and $0.2 million, respectively, to stock compensation expense based on amortizing the fair value over the appropriate service period.

12. RELATED PARTY TRANSACTIONS

Pursuant to an agreement dated December 16, 2004, as amended, we agreed with R.C. Boyd Enterprises, a Delaware corporation, to become the lead sponsor of a television production called Honey Hole ("Honey Hole Production"). As part of our sponsorship, we provided fishing and outdoor opportunities for children with cancer, children from abusive family situations and children of military veterans. We were entitled to receive two thirty-second commercials during all broadcasts of the Honey Hole Production and received opening and closing credits on each episode. Randall Boyd is the sole shareholder of R.C. Boyd Enterprises and is a member of our Board of Directors. Pursuant to an agreement dated as of December 5, 2007, as of December 31, 2008, we are no longer a Honey Hole Production sponsor. We paid no money to R.C. Boyd Enterprises after December 31, 2008. During the years ended June 30, 2009, 2008 and 2007, we paid $75,000, $150,000 and $150,000, respectively, for sponsorship activities.

13. FAIR VALUE MEASUREMENTS

SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements

F-28

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. FAIR VALUE MEASUREMENTS (Continued)

that require or permit fair value measurement. We adopted SFAS No. 157 on July 1, 2008. The initial adoption of SFAS 157 had no material impact to our financial position, results of operations or cash flows.

Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. If observable prices or inputs are not available, unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We primarily apply a market approach for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation includes the effect of potential non-performance by the counterparties.

Beginning July 1, 2008, 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. SFAS 157 establishes a fair value hierarchy 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 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

F-29

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. FAIR VALUE MEASUREMENTS (Continued)

remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

The estimated fair values of derivatives included in the consolidated balance sheet at June 30, 2009 are summarized below.

In thousands

Derivative assets (Level 2):
	Crude oil collars and price floors—current	$	2,507
	Crude oil collars and price floors—noncurrent		1,569
	Natural gas collars and price floors—current		2,448
	Natural gas collars and price floors—noncurrent		1,101
	Interest rate swap—noncurrent		212
Derivative liability (Level 2)
	Interest rate swap—current		(159	)

Net derivative assets (Level 2)		$	7,678

Asset retirement obligation (Level 3)		$	(2,904	)

At September 30, 2008, our net derivative liability was classified as Level 3 due to the subjectivity of our valuation for the effect of our own credit risk. At June 30, 2009, the subjective valuation of our own credit risk has an immaterial impact to our derivative valuation. Therefore, we have reclassified our derivative assets as Level 2 at June 30, 2009. The following is a reconciliation of Level 3 measurements for the year ended June 30, 2009.

		Unrealized Losses For Level 3 Assets/Liabilities Outstanding at June 30, 2008			Total Gains or Losses(a)			Purchases, Sales, Issuances, and Settlements, net			Transfers out of Level 3			Ending balance			Unrealized Gains for Level 3 Assets/Liabilities Outstanding at June 30, 2009

Derivatives		$	(2,152	)	$	17,565		$	(1,282	)	$	(14,131	)	$	—		$	—

(a): Total realized and unrealized gains are included in gain (loss) on commodity derivatives in the consolidated statements of operations.

F-30

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. FAIR VALUE MEASUREMENTS (Continued)

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 12 months ended June 30, 2009.

In thousands		Total Net Derivative Assets			Asset Retirement Obligation

Balance at June 30, 2008		$	(26,243	)	$	3,403
	Unrealized gain on derivatives		36,900			—
	Sale of "price floor" contracts		(1,169	)		—
	Settlements, net		(1,810	)		—
	Accretion of discount		—			305
	Change in assumptions		—			(626	)
	Liabilities incurred for properties acquired		—			18
	Liabilities incurred for properties drilled		—			21
	Sale of Pantwist, LLC (Note 8)		—			(90	)
	Sale of Corsicana Properties (Note 8)		—			(102	)
	Liabilities settled		—			(25	)

Balance at June 30, 2009		$	7,678		$	2,904

The change from net derivative liabilities of $26.2 million at June 30, 2008 to net derivative assets of $7.7 million at June 30, 2009 is primarily attributable to the steep decline in crude oil and natural gas prices.

14. IMPAIRMENT OF LONG-LIVED ASSETS AND GOODWILL

The decline in commodity prices created an uncertainty in the likelihood of developing our reserves associated with our Barnett Shale natural gas properties (the "Barnett Shale Properties") within the next five years. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties and a $0.7 million pre-tax impairment to the goodwill associated with our subsidiary which holds the equity in our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline.

During the quarter ended September 30, 2008, we recorded a $3.5 million pre-tax impairment on our Corsicana Properties as it became unlikely that we would develop this asset within the next five years. During the quarter ended December 31, 2008, this $3.5 million charge was reclassified as part of income from discontinued operations as shown on our consolidated statements of operations. As previously discussed in Note 8, on December 2, 2008, we sold our interest in the Corsicana Properties for $0.3 million.

The fair values for our Barnett Shale and Corsicana Properties were determined using estimates of future net cash flows, discounted to a present value, which is considered "Level 3" inputs as previously discussed in Note 13.

F-31

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. ASSET RETIREMENT OBLIGATION

Our asset retirement obligation ("ARO") primarily represents the estimated present value of the amount we will incur to plug and abandon our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our ARO by calculating the present value of estimated cash flows related to the liability. At June 30, 2009, our liability for ARO was $2.9 million, of which $2.8 million was considered long term. At June 30, 2008, our liability for ARO was $3.4 million, of which $2.1 was considered long term and included $0.2 million reclassified to discontinued operations as previously discussed in Note 8. Our ARO is recorded as current or non-current liabilities based on the estimated timing of the related cash flows. For the years ended June 30, 2009, 2008 and 2007, we have recognized accretion expense, net of discontinued operations, of $0.3 million, $0.1 million and $0.1 million, respectively.

The following table describes the changes in our ARO for the years ended June 30, 2009 and 2008 (in thousands):


Asset retirement obligation at June 30, 2007		$	2,415
	Accretion of discount		219
	Change in estimate		740
	Liability incurred for properties drilled		93
	Liabilities settled		(64	)

Asset retirement obligation at June 30, 2008			3,403
	Accretion of discount		305
	Change in estimate		(626	)
	Liabilities incurred for properties acquired		18
	Liability incurred for properties drilled		21
	Sale of Pantwist, LLC (Note 8)		(90	)
	Sale of Corsicana Properties (Note 8)		(102	)
	Liabilities settled		(25	)

Asset retirement obligation at June 30, 2009		$	2,904

For the year ended June 30, 2009, the change in estimate resulted primarily from a change in estimated timing to plug and abandon wells. For the year ended June 30, 2008, the change in estimate resulted primarily from an increase in estimated costs to plug and abandon wells.

F-32

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. INCOME TAXES

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax provisions. Our income tax expense (benefit) is as follows:

			Years Ended June 30,

In Thousands			2009			2008			2007
Current income tax expense (benefit)
	Federal		$	—		$	—		$	—
	State			(61	)		114			53

		Total current tax expense (benefit)		(61	)		114			53
Deferred income tax benefit
	Federal			(4,952	)		(11,551	)		(2,847	)
	State			301			(330	)		(176	)

		Total deferred tax benefit		(4,651	)		(11,881	)		(3,023	)

Total income tax benefit			$	(4,712	)	$	(11,767	)	$	(2,970	)

A reconciliation of the differences between our applicable statutory tax rate and our effective income tax rate for the years ended June 30, 2009, 2008 and 2007 is as follows:

	Years Ended June 30,

In Thousands, except %	2009			2008			2007
Rate		35	%		35	%		35	%
Tax at statutory rate	$	(5,748	)	$	(11,466	)	$	(2,896	)
State taxes		240			(161	)		—
Increase (decrease) resulting from:
Change in Texas tax law		—			—			(84	)
Permanent and other		77			(140	)		(12	)
Differences in stock-based compensation expense		472			—			—
Goodwill Impairment		247			—			—
Change in valuation allowance		—			—			22

Income tax benefit	$	(4,712	)	$	(11,767	)	$	(2,970	)

F-33

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. INCOME TAXES (Continued)

A schedule showing the significant components of the net deferred tax liability as of June 30, 2009 and 2008 are as follows:

			Years Ended June 30,

In Thousands			2009			2008
Current
Deferred tax assets:
	Unrealized loss on commodity derivatives		$	—		$	3,592
	Other			305			—

		Total current deferred tax assets		305			3,592

Deferred tax liabilities:
	Unrealized gain on commodity derivatives			(1,736	)		—

		Total current deferred tax liabilities		(1,736	)		—

	Net current deferred tax asset (liability)		$	(1,431	)	$	3,592

Long-Term
Deferred tax assets:
	Deferred compensation expense		$	2,327		$	2,072
	Net operating loss carryovers			12,463			6,415
	Unrealized loss on commodity derivatives			—			7,356
	Other			415			260

				15,205			16,103
Less: valuation allowance				(770	)		(770	)

	Total long-term deferred tax assets			14,435			15,333
Deferred tax liabilities:
	Difference in book and tax bases:
		Acquired oil and gas properties		(36,122	)		(41,789	)
		Other properties		—			394
		Unrealized gain on commodity derivatives		(1,144	)		—

		Total long-term deferred tax liabilities		(37,266	)		(41,395	)

Net long-term deferred tax liability			$	(22,831	)	$	(26,062	)

In May 2006, the State of Texas enacted legislation for a Texas margin tax which restructured the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new "taxable margin" component. As the tax base for computing Texas margin tax is derived from an income-based measure, we have determined the margin tax is an income tax and the effect on deferred tax assets and liabilities of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date.

At June 30, 2009 and 2008, we had net operating loss ("NOL") carryforwards for tax purposes of approximately $34.6 million and $17.8 million, respectively. The remaining net operating losses principally expire between 2024 and 2029. $2.2 million of these NOL carryforwards will be unavailable to offset any future taxable income due to limitations from change in ownership, which occurred at our

F-34

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. INCOME TAXES (Continued)

merger in May 2004, as defined in Section 382 of the Internal Revenue Service code. The tax effect of this limitation is recorded as a valuation allowance of $770,000 at both June 30, 2009 and 2008.

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

F-35

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

Settled Cases

On May 1, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1923, Chisum Family Partnership, Ltd. v. Cano, W.O. Energy of Nevada, Inc.,

F-36

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

W. O. Operating Company, Ltd. and WO Energy, Inc. (the "Chisum" case). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleged negligence and trespass and (ii) sought damages of $53,738.82, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs sought exemplary damages. The claims of all plaintiffs and intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On May 2, 2007, the following lawsuit was filed in the 84th Judicial District Court of Hutchinson County, Texas, Cause No. 37,619, Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Burgess case"). Eleven plaintiffs claimed that electrical wiring and equipment relating to oil and gas operations of the Company or certain of its subsidiaries started a wildfire that began on March 12, 2006 in Carson County, Texas. Five of the plaintiffs were former plaintiffs in the Adcock matter. The plaintiffs (i) alleged negligence, res ipsa loquitor, nuisance, and trespass and (ii) sought damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $1,997,217.86. In addition, the plaintiffs sought (i) reimbursement for their attorneys' fees and (ii) exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of all plaintiffs were

F-37

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

resolved through a Settlement and Release Agreement effective November 5, 2008 and were dismissed with prejudice.

On January 10, 2008, Philip L. Fletcher intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleged negligence, trespass and nuisance and (ii) sought damages of $120,408, including, but not limited to, damages to his livestock, attorneys' fees and exemplary damages. The intervenor also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

On January 15, 2008, the Jones and McMordie Ranch Partnership intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleged negligence, trespass and nuisance and (ii) sought damages of $86,250.71, including, but not limited to, damages to his livestock, attorneys' fees and exemplary damages. The intervenor also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. The claims of this intervenor were resolved through a Settlement and Release Agreement effective December 9, 2008 and were dismissed with prejudice.

F-38

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

On February 11, 2008, the following lawsuit was filed in the 48th Judicial District Court of Tarrant County, Texas: Cause No. 048-228763-08, Abraham Equine, Inc. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Abraham Equine case"). The plaintiff claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleged negligence, trespass and nuisance and (ii) sought damages of $1,608,000, including, but not limited to, damages to its land, livestock and lost profits. In addition, the plaintiff sought (i) reimbursement for its attorneys' fees and (ii) exemplary damages. The plaintiff also claimed that Cano and its subsidiaries were jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. This suit (along with the claims of Abraham Brothers, LP, Edward C. Abraham, Salem A. and Ruth Ann Abraham and Jason M. Abraham, discussed above) was resolved through a Settlement and Release Agreement effective October 12, 2008 and were dismissed with prejudice.

F-39

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

took the motion under advisement. The claims of plaintiffs were resolved through a Settlement and Release Agreement effective December 10, 2008 and were dismissed with prejudice.

On December 18, 2007, the following lawsuit was filed in the 348th Judicial District Court of Tarrant County, Texas, Cause No. 348-227907-07, Norma Valenzuela, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. (the "Valenzuela case"). Six plaintiffs, including the two plaintiffs and intervenor from the nonsuited Martinez case, claimed that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) alleged negligence and (ii) sought actual damages in the minimal amount of $4,413,707 for the wrongful death of four relatives, Manuel Dominguez, Roberto Chavira, Gerardo Villarreal and Medardo Garcia, who they claimed died as a result of the fire. In addition, plaintiffs sought (i) reimbursement for their attorneys' fees and (ii) exemplary damages. The plaintiffs also claimed that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement. The claims of plaintiffs were resolved through a Settlement and Release Agreement effective April 9, 2009 and were dismissed with prejudice.

Insurance and Other Settlements Related to the Fire Litigation

F-40

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

business days of February 9, 2007 the amount of $6,699,827 comprising the following: (a) the $1,000,000 policy limits of the primary policy; (b) the $5,000,000 policy limits of the excess policy; (c) $500,000 for future defense costs; (d) $144,000 as partial payment for certain unpaid invoices for litigation related expenses; (e) all approved reasonable and necessary litigation related expenses through December 21, 2006 that are not part of the above-referenced $144,000; and (f) certain specified attorneys' fees. During February 2007, we received the $6,699,827 payment from Mid-Con. Of this $6,699,827 amount, the payments for policy limits amounting to $6,000,000 were recorded as a liability under deferred litigation credit as presented on our consolidated balance sheet.

On March 6, 2009, the Amended and Restated Escrow Agreement ("Escrow Agreement") terminated in accordance with its terms that was entered into on June 18, 2007 by and among Cano, the Estate of Miles O'Loughlin and Scott White (the "W.O. Sellers") and The Bank of New York Trust Company, N.A. (the "Trustee") related to the November 2005 purchase of W.O. Energy of Nevada, Inc., and its subsidiaries, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and WO Energy, Inc. (collectively "W.O."). Pursuant to the terms of the Escrow Agreement, the Trustee returned to us 434,783 shares of Cano common stock owned by the W.O. Sellers which had been held in trust for our benefit. The shares are held by us as treasury stock. In addition, the W.O. Sellers provided additional consideration (collectively, the 434,783 shares and the additional consideration being the "W.O. Settlement").

Securities Litigation against Outside Directors

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

F-41

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

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

Environmental

Leases

Effective June 1, 2009, we entered into a non-cancelable operating lease for our principal executive offices in Fort Worth, Texas. The lease expires on May 31, 2014. Our remaining obligation for the life of the lease is $3.0 million. In addition, during October 2005 we entered into a five-year operating lease for our field offices in Pampa, Texas expiring on October 1, 2010. Future minimum rentals due under our non-cancellable operating leases were as follows on June 30, 2009:

In Thousands		2010			2011			2012			2013			2014			Total

Total operating lease obligations		$	516		$	603		$	630		$	664		$	635		$	3,048

Rent expense amounted to $0.3 million, $0.4 million, and $0.3 million for the years ended June 30, 2009, 2008 and 2007, respectively.

F-42

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. COMMITMENTS AND CONTINGENCIES (Continued)

Employment Contracts

We have employment contracts with our executives that specify annual compensation, and provide for potential payments up to three times the annual salary and bonuses and immediate vesting of unexercised stock options and restricted stock under termination or change in control circumstances. The annual salaries and contract termination dates for each executive are as follows:

	Annual Compensation

Chief Executive Officer	$	545,144	May 31, 2011
Senior Vice President and Chief Financial Officer		250,000	June 23, 2011
Senior Vice President of Operations		250,000	May 31, 2011
Vice President and Principal Accounting Officer		187,000	May 31, 2011
Vice President, General Counsel and Corporate Secretary		170,000	May 31, 2011

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

All of our operations are directly related to oil and natural gas producing activities located in Texas, Oklahoma and New Mexico.

Capitalized Costs Relating to Oil and Gas Producing Activities

		June 30,

In Thousands		2009			2008
Mineral interests in oil and gas properties:
	Proved	$	78,777		$	87,307
	Unproved		—			—
Wells and related equipment and facilities			157,202			137,734
Support equipment and facilities used in oil and gas producing activities			3,592			2,566
Uncompleted wells, equipment and facilities			49,286			47,568

Total capitalized costs			288,857			275,175
Less accumulated depletion and depreciation			(40,208	)		(10,281	)

Net capitalized costs		$	248,649		$	264,894

At June 30, 2009, accumulated depletion and depreciation expense of $40.2 million includes impairment of our Barnett Shale Properties totaling $26.7 million, as previously discussed in Note 14.

F-43

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Continued)

Costs Incurred in Oil and Gas Producing Activities

	Years Ended June 30,

In Thousands	2009		2008		2007
Acquisition of proved properties	$	77	$	899	$	9,874
Acquisition of unproved properties		—		—		—
Development costs		48,657		77,868		40,052
Exploration costs		2,967		6,629		5,395

Total costs incurred, net of sale of oil and gas properties	$	51,701	$	85,396	$	55,321

Proved Reserves (Unaudited)

Our proved oil and natural gas reserves have been estimated by independent petroleum engineers, Miller and Lents, LTD for the years ended June 30, 2009 and 2008, and Forrest A. Garb & Associates, Inc. for the year ended June 30, 2007. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history, acquisitions of crude oil and natural gas properties and changes in economic factors.

Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimated proved reserves may result from lower prices, adverse operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomic to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our crude oil and natural gas properties for impairment. Seventy-nine percent of our proved reserves are classified as proved undeveloped reserves. Capital expenditures forecasted in our reserve report amount to approximately $332.7 million throughout the life of our reserves. Further, capital expenditures exceed our expected operating cash flows in our reserve report for the four-year period succeeding June 30, 2009. We are dependent upon our cash flow from operations and the credit and capital markets to fund the development of these

F-44

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Continued)

reserves. As we have done during each year of our existence, 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.

Our proved reserves are summarized in the table below.



Reserves at July 1, 2006	33,868		69,102		45,385
Purchases of minerals in place	7,757		8,159		9,117
Extensions and discoveries	—		64,940		10,823
Sale of minerals in place	(216	)	(2,132	)	(571	)
Revisions of prior estimates	1,204		7,712		2,489
Production	(283	)	(1,441	)	(523	)

Reserves at June 30, 2007	42,330		146,340		66,720
Purchases of minerals in place	1,592		1,680		1,872
Extensions and discoveries	3,894		10,861		5,704
Revisions of prior estimates	(8,403	)	(73,097	)	(20,586	)
Production	(297	)	(1,345	)	(521	)

Reserves at June 30, 2008	39,116		84,439		53,189
Extensions and discoveries	2,544		472		2,623
Sale of minerals in place	(1,240	)	(7,886	)	(2,554	)
Revisions of prior estimates	(1,338	)	(14,191	)	(3,703	)
Production	(311	)	(881	)	(458	)

Reserves at June 30, 2009	38,771		61,953		49,097

Proved developed reserves at June 30, 2007	6,555		28,450		11,297
Proved developed reserves at June 30, 2008	8,118		29,886		13,099
Proved developed reserves at June 30, 2009	7,027		18,322		10,081

The base prices used to compute the crude oil and natural gas reserves represent the NYMEX oil and natural gas prices at June 30, 2009, 2008 and 2007, respectively. For the reserves at June 30, 2009, the crude oil and natural gas prices were $69.89 per barrel and $3.71 per MMbtu, respectively. For the reserves at June 30, 2008, the crude oil and natural gas prices were $140.00 per barrel and $13.15 per MMbtu, respectively. For the reserves at June 30, 2007, the crude oil and natural gas prices were $70.47 per barrel and $6.40 per MMbtu, respectively.

Effective July 1, 2009 (for our next fiscal year ending June 30, 2010), the base prices used to compute reserves will conform to recent SEC regulations that specify an average price should be used during the company's fiscal year based on NYMEX commodity prices on the first day of each of the 12 months.

For the reserves at June 30, 2009, the extensions and discoveries pertain to our drilling and completing wells, and results of the waterflood project in the San Andres formation at our Cato Properties.

F-45

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Continued)

For the reserves at June 30, 2009 and 2007, the sales of minerals in place pertain to our divestitures of oil and natural gas properties located in Texas and Oklahoma, respectively.

For the reserves at June 30, 2009, the reduction for revisions of prior estimates pertain to the impairments of our Barnett Shale Properties (Note 14) of 2,269 MBOE and other revisions of 1,434 MBOE driven primarily from the decline in commodity prices and forecast changes which reduced the economic life of our assets, as compared to proved reserves as of June 30, 2008. The specific field changes are as follows:

•: At the Desdemona-Barnett Shale, production performance due to price accounted for 422 MBOE of negative revisions in PDP, partially offset by a positive 83 MBOE (43 MBOE PDP and 40 MBOE PDNP) at the Desdemona Duke Sands projects due to improved recoveries.
•: At the Davenport Properties, commodity price-related effects reduced PDP reserves by 211 MBOE.
•: At the Nowata Properties, improved recoveries increased PDP reserves by 115 MBOE.
•: At the Panhandle Properties, PDP reserves decreased 1,324 MBOE largely as a result of transferring 700 MBOE to PUD reserves, commodity price-related effects and production, which was partially offset by increased PUD reserves of 324 MBOE—a net reduction of 1,000 MBOE.

For the reserves at June 30, 2008 and 2007, the purchases of minerals in place pertain to our acquisitions of oil and natural gas properties located in the Texas Panhandle ("Panhandle Properties") and southwestern New Mexico ("Cato Properties").

For the reserves at June 30, 2008, the extensions and discoveries pertain to our drilling and completing wells at the Cato Properties and the Panhandle Properties, and results of the waterflood project at the Panhandle Properties.

For the reserves at June 30, 2008, the reduction for revisions of prior estimates primarily pertains to our Desdemona, Panhandle and Pantwist Properties.

•: For the Desdemona—Barnett Shale, we considered the lower production performance from the existing wells and current industry practice that limited the number of horizontal offset PUD locations that could be booked against existing wells from eight to two locations. Therefore, PUD reserves were reduced by approximately 3.0 MMBOE due to lower performance results from the existing wells and further reduced by another 4.6 MMBOE as the number of PUD drilling locations decreased from 76 to 40. Also, as a result of production performance, PDP and PDNP reserves were decreased by 0.4 MMBOE.
•: For the Panhandle Properties, we reclassified 5.6 MMBOE from PUD to probable reserves as there were insufficient analogs to the Granite Wash formation to justify PUD classification. In addition, we could not commit to developing the Granite Wash within five years.
•: For the Pantwist Properties, based on current industry practice, we reclassified 4.4 MMBOE of PUD reserves to probable reserves as we could not commit to developing Pantwist's PUD reserves within five years.

F-46

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Continued)

•: The reductions in crude oil and natural gas reserves also included the following less significant reductions as a result of production performance: (i) at the Corsicana Field, PDNP reserves were reduced by 0.1 MMBOE; (ii) at Desdemona, PDP reserves were reduced by 0.1 MMBOE; and (iii) at Nowata, PDP reserves were reduced by 0.2 MMBOE.

The reductions in crude oil and natural gas reserves were partially offset by a proved reserve increases of 4.4 MMBOE at the Cato Field, where third-party engineering and geologic studies confirmed increases to original oil in place estimates and PUD reserves, and an infill drilling program resulted in an increase in PDP and PDNP reserves. There were also the following proved reserve increases for positive performance due to price increases: (i) at Panhandle, PDP reserves were increased by 0.2 MMBOE; (ii) at Davenport, PDP reserves were increased by 0.05 MMBOE; (iii) at Desdemona, PDNP reserves were increased by 0.3 MMBOE; (iv) at Corsicana, PDP and PDNP reserves, in the aggregate, were increased by 0.02 MMBOE; and (v) at Pantwist, PDP reserves were increased by 0.01 MMBOE. We also transferred reserves of 0.4 MMBOE from PDNP to PDP at Davenport and reserves of 1.4 MMBOE from PUD to PDP at the Panhandle Properties.

For the reserves at June 30, 2007, the extensions and discoveries pertain to our drilling and completing wells in the Barnett Shale formation at our Desdemona Properties.

Standardized Measure (Unaudited)

The standardized measure of discounted future net cash flows ("standardized measure") and changes in such cash flows are prepared using assumptions including the use of year-end prices for oil and natural gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% annual discount rate.

Estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such abandonment costs are recorded as a liability on the consolidated balance sheets, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired.

The standardized measure does not represent management's estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.

Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves, proved undeveloped reserve additions attributable to increased development activity, reduced reserves due to lower performance from the existing wells, reduced reserves to comply with current industry practice that limited the number of PUD locations that could be booked against existing wells and lower reserves if a company is unable to commit to developing PUD reserves within five years.

F-47

Table of Contents

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Continued)

Standardized Measure of Discounted Future Cash Flows (Unaudited)

The standardized measure of discounted estimated future net cash flows related to proved crude oil and natural gas reserves for the years ended June 30, 2009, 2008 and 2007 is as follows:

In Thousands	2009			2008			2007

Future cash inflows	$	2,751,854		$	6,695,248		$	3,902,164
Future production costs		(767,743	)		(1,251,161	)		(933,538	)
Future development costs		(332,677	)		(392,248	)		(324,787	)
Future income taxes		(535,300	)		(1,759,461	)		(920,000	)

Future net cash flows		1,116,134			3,392,378			1,723,839
10% annual discount		(834,122	)		(1,879,835	)		(1,022,808	)

Standardized measure of discounted future net cash flows	$	282,012		$	1,412,543		$	701,031

Changes in Standardized Measure of Discounted Future Cash Flows: (Unaudited)

The primary changes in the standardized measure of discounted estimated future net cash flows for the years ended June 30, 2009, 2008 and 2007 are as follows:

In Thousands	2009			2008			2007

Balance at beginning of year	$	1,412,543		$	701,031		$	342,464
Net changes in prices and production costs		(1,598,659	)		1,700,142			(7,186	)
Net changes in future development costs		(36,746	)		(111,830	)		(91,588	)
Sales of oil and gas produced, net		(6,552	)		(25,788	)		(15,765	)
Purchases of reserves		—			85,048			174,645
Sales of reserves		(94,357	)		—			(10,953	)
Extensions and discoveries		38,256			322,754			207,340
Revisions of previous quantity estimates		(54,017	)		(935,281	)		47,699
Previously estimated development costs incurred		47,590			89,171			43,802
Net change in income taxes		349,339			(392,541	)		(97,089	)
Accretion of discount		224,235			113,830			57,043
Other		380			(133,993	)		50,619

Balance at end of year	$	282,012		$	1,412,543		$	701,031

F-48