Edgar Filing: CANO PETROLEUM, INC

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: June 30, 2007
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)		(I.R.S. Employer Identification Number)

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

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

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		AMERICAN STOCK EXCHANGE

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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (check one)

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by 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 29, 2006 was $128,639,619. (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, as of September 6, 2007 was 33,083,098 shares.

DOCUMENTS INCORPORATED BY REFERENCE

If the information required by Part III of this Form 10-K is not included in a previously filed amendment to this Form 10-K, portions of the registrant's Proxy Statement for the 2007 Annual Meeting of Stockholders, expected to be filed on or before October 29, 2007, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
PART I
Item 1 and 2.	Business and Properties	1
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	23
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	27
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	29
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	47
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
Item 9A.	Controls and Procedures	47
Item 9B.	Other Information	50
PART III
Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance	50
Item 11.	Executive Compensation	50
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions and Director Independence	50
Item 14.	Principal Accountant Fees and Services	50
PART IV
Item 15.	Exhibits and Financial Statement Schedules	51
SIGNATURES		52

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 a growing independent oil and natural gas company. Our strategy is to acquire assets with a high ratio of non-proven or proved undeveloped reserves suitable for EOR techniques, primarily on the onshore United States for a low cost. We intend to convert these non-proven and/or proved undeveloped reserves into proved producing reserves by applying water, gas or chemical flooding and other EOR techniques. During our first three years of operations, our primary focus has been to achieve growth through acquiring interests in existing, mature fields in Texas, Oklahoma and New Mexico. We believe the portfolio of oil and natural gas properties we have acquired to date provides suitable opportunities to apply EOR techniques. As of June 30, 2007, we had proved reserves of 66,720 MBOE, of which 8,454 MBOE were proved producing, 2,843 MBOE were proved non-producing, and 55,423 MBOE were proved undeveloped.

We were organized 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. 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

Davenport Properties. In the Davenport Merger, we acquired the Davenport Properties in Lincoln County, Oklahoma for 5,165,000 shares of our common stock and $1,650,000 cash. Proved reserves as of June 30, 2007 attributable to the Davenport Properties are 1,488 MBOE, of which 552 MBOE are proved producing, 936 MBOE are proved non-producing and none of which are proved undeveloped. As a result of ongoing waterflood operations on the Davenport Properties, current production is approximately 80 BOEPD.

Nowata Properties. In September 2004, we acquired the Nowata Properties which consisted of more than 220 wells producing from the Bartlesville Sandstone for approximately $2.6 million. Proved reserves as of June 30, 2007 attributable to the Nowata Properties are 1,687 MBOE, all of which are proved producing. As a result of prior waterflood operations on the Nowata Properties, current net production is approximately 200 BOEPD.

Desdemona Properties. In March 2005, in connection with our acquisition of Square One Energy, Inc. for $7.6 million, consisting of $4.0 million in cash and 888,888 shares of our common stock valued at $3.96 per share, we acquired a 100% working interest in the Desdemona Properties which are 11,068 acres in mature oil fields in central Texas. Proved reserves as of June 30, 2007 attributable to the Desdemona Properties are 11,851 MBOE, of which 711 MBOE are proved producing, 1,175 MBOE are proved non-producing and 9,965 MBOE are proved undeveloped. Current production is approximately 205 BOEPD. These properties have not been previously waterflooded and have mineral rights to the Barnett Shale formation.

Corsicana Properties. During 2005, we began acquiring oil and natural gas leases comprising the Corsicana Properties. Currently, we have a 100% working interest in 341 acres under lease. The Corsicana Properties were the subject of a proved surfactant-polymer chemical injection pilot in the 1980s and contain proved reserves as of June 30, 2007 of 205 MBOE, of which 108 MBOE are proved non-producing and 97 MBOE are proved undeveloped.

Panhandle Properties. On November 29, 2005, through our acquisition of W.O. Energy of Nevada, Inc. for an adjusted cash price of $48.4 million and 1,791,320 shares of common stock with an aggregate value of approximately $8.24 million, we acquired inventory, 10 workover rigs and related equipment, 480 producing wells, 40 water disposal wells and 380 idle wells on approximately 20,000 acres in Carson, Gray and Hutchinson Counties, Texas which constitute the Panhandle Properties. Proved reserves as of June 30, 2007 attributable to the Panhandle Properties are 35,547 MBOE, of which 3,397 MBOE are proved producing, 32,150 MBOE are proved undeveloped and none of which is proved non-producing. Current production is approximately 650 BOEPD. We are progressing with the execution of Phase I of our waterflood development plan at the Cockrell Ranch Unit. These properties have not been previously waterflooded.

Pantwist Properties. Effective February 1, 2006, our wholly-owned subsidiary, Pantwist LLC, acquired additional properties, including 167 wells and 2 workover rigs and covering approximately 9,700 acres in the Panhandle field which are the Pantwist Properties for a cash purchase price of $23.4 million. Proved reserves as of June 30, 2007 attributable to the Pantwist Properties are 6,829 MBOE, of which 1,883 MBOE are proved producing, 4,946 MBOE are proved undeveloped and none of which are proved non-producing. Current production is approximately 350 BOEPD. These properties have not been previously waterflooded.

New Mexico Properties—New Acquisition. In addition to the capital spending previously discussed, we completed an acquisition on March 30, 2007 with an effective date of February 1, 2007. Cano Petro of New Mexico, Inc., our wholly-owned subsidiary, acquired certain oil and gas properties in the Permian Basin 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, which was valued at $4.59 per share. Proved reserves as of June 30, 2007 attributable to the New Mexico Properties are 9,112 MBOE, of which 224 MBOE are proved producing, 8,264 MBOE are proved undeveloped and 624 MBOE are proved non-producing. Current production is approximately 50 BOEPD. The New Mexico Properties include roughly 20,000 acres and 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. We believe that the Cato Field is the largest San Andres field in the Permian Basin that has never been waterflooded.

Sale of Rich Valley Properties. In July 2004, we acquired the Rich Valley Properties in Grant County, Oklahoma, through our acquisition of Ladder Companies, Inc., a Delaware corporation, for approximately $2.2 million. On June 11, 2007, we sold the Rich Valley Properties for net proceeds of $6.9 million. At the time of sale the production was approximately 110 BOEPD.

Planned Development Program

During our first two years of operations through June 30, 2006, our primary focus was to achieve growth through acquiring existing, mature oil and natural gas fields. During March 2007, we continued to acquire properties by acquiring Permian Basin oil and natural gas properties located in New Mexico. We believe the portfolio of oil and natural gas properties that we have acquired thus far provides ample opportunities to apply our operational strategy. As of June 30, 2007, we had proved reserves of 66,720 MBOE, of which 8,454 MBOE were proved producing, 2,843 MBOE were proved non-producing, and 55,423 MBOE were proved undeveloped.

During the fiscal year ending June 30, 2007, our primary emphasis has been to achieve growth by developing our existing oil and natural gas properties through development activities such as waterflooding and EOR technology. We will continue to evaluate potential acquisition targets that are consistent with our operational strategy. These development activities are more clearly defined later

under "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Development Update."

Waterflood operations and EOR techniques such as surfactant-polymer chemical injection involve significant capital investment and an extended period of time, generally a year or longer, from the initial phase of a program until increased production occurs. Generally, surfactant polymer injection is regarded as more risky compared to waterflood operations. Our ability to successfully convert proved undeveloped reserves to proved producing reserves will be contingent upon our ability to obtain future financing and/or raise additional capital, and further, is greatly contingent upon inherent uncertainties associated with the production of oil and natural gas as well as price volatility. See "Risk Factors."

Industry Conditions

We believe significant acquisition opportunities will continue to exist primarily because the major energy companies and large independents continue to focus their attention and resources toward the discovery and development of large fields. During the past several years, the major companies have been divesting themselves of their mature oilfields, a trend management expects will continue. Also, the recent economics of the oil and natural gas market have improved as prices have risen substantially. These conditions provide ample opportunities for smaller independent companies to acquire and exploit mature U.S. fields. We expect that there will be increased competition for such properties in the future.

Our Strategy

•: Acquire Strategic Assets. We seek to acquire low-cost assets with a high ratio of non-proven or proved undeveloped reserves suitable for waterflood and EOR techniques, primarily in the onshore United States. We believe we have acquired an attractive portfolio of assets to implement our business plan. We will continue to selectively target potential acquisition candidates in a disciplined manner, which involves being financially prudent and acquiring assets that meet our engineering and operational standards. We focus on U.S. operations. Accordingly, we are not subject to geopolitical uncertainties, dependence on foreign sources and other issues related to overseas operations.
•: No Exploration Risk. Our portfolio is comprised of mature fields with proven reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on exploration drilling and the high degree of speculation in making new discoveries.
•: Exploit and Develop Existing Properties. We intend to add proved reserves to, and increase production from, our existing properties through the application of advanced technologies, including water, gas or chemical flooding and other EOR techniques. We believe that our management team has a proven track record of exploiting underdeveloped properties to increase reserves and cash flow.
•: Maintain a Low Cost Structure. We intend to maintain a low cost structure through maintaining efficient operations and operating control. We intend to be the working interest operator in a high proportion of our properties. This allows us to exercise more control over expenses, capital allocation, and the timing of development and exploitation activities in our fields. It also enables us to implement controls over our costs to ensure prudent expenditures. Further, we employ engineering and geological consultants to aid in evaluating the economic merits of drilling plans and potential acquisitions on a case-by-case basis rather than staffing these positions, enabling us to maintain low fixed costs.

September 2006 Financing

On September 6, 2006, we sold in a private placement, preferred stock, common stock and associated warrants for aggregate gross proceeds of approximately $80.9 million. We used approximately $68.75 million to repay our long-term debt. The remainder was used for working capital and general corporate purposes, including the funding of our fiscal year 2007 capital budget.

Proved Reserves

The following table summarizes proved reserves as of June 30, 2007 and was prepared according to the rules and regulations of the Securities and Exchange Commission.

	Nowata	New Mexico	Davenport	Desdemona	Corsicana	Panhandle	Pantwist	Total
Oil - MBbls	1,554	7,754	1,403	374	206	26,251	4,686	42,228
Gas - MMcf	795	8,151	507	68,862	—	55,776	12,860	146,951
Oil Equivalent (MBOE)	1,687	9,112	1,488	11,851	206	35,547	6,829	66,720

Our proved oil and natural gas reserves as of June 30, 2007 have been estimated by Forrest A. Garb & Associates, Inc., independent petroleum engineers. As defined in the Securities and Exchange Commission 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 considerations of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injections) are included in the "proved" classification when successful testing by a pilot project, or the operations of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

We have not reported our reserves to any federal authority or agency other than with the Securities and Exchange Commission pursuant to our filings with the Securities and Exchange Commission.

Our proved reserves equate to 66,720 MBOE of proved reserves, consisting of (13%) or 8,454 MBOE of proved producing reserves, 2,843 MBOE (4%) of proved non-producing reserves and 55,423 MBOE (83%) of proved undeveloped reserves.

Reserves were estimated using crude oil and natural gas prices and production and development costs in effect on June 30, 2007. On June 30, 2007, the crude oil and natural gas prices were $70.47 per barrel and $6.40 per Mcf, 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, 2007, 2006 and 2005.

		Years Ended June 30,
		2007		2006		2005
Operating Revenues(1): (000's)		$	28,353	$	15,860	$	3,764
Sales:
	Oil (MBbls)		274		180		75
	Gas (MMcf)		1,313		531		18
	MBOE		493		268		78
Average Price(1):
	Oil ($/Bbl)	$	61.95	$	63.32	$	48.98
	Gas ($/Mcf)	$	8.67	$	8.38	$	5.37
	$/BOE	$	57.55	$	59.03	$	48.33
Expense (per BOE):
Lease operating		$	21.78	$	22.41	$	26.56
Production and ad valorem taxes		$	5.00	$	4.30	$	2.87
General and administrative expense, net		$	25.87	$	28.37	$	61.03
Depreciation, depletion and amortization		$	8.74	$	6.88	$	4.76
Total		$	61.39	$	61.96	$	95.22

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

Productive Wells and Acreage

The following table shows our gross and net interest in productive oil and natural gas working interest wells as of September 6, 2007. Productive wells include wells currently producing or capable of production.

Gross(1)						Net(2)
Oil		Gas		Total		Oil		Gas		Total
1,864		162		2,026		1,778		145		1,923

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

We operate all of the gross producing wells presented above. As of September 6, 2007, we had no wells containing multiple completions.

On September 6, 2007, we had total acreage of 72,888 gross acres and 69,493 net acres, all of which was considered developed acres. 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, 2007, 2006 and 2005. We own 100% working interests.

			Years Ended June 30,
			2007	2006	2005
			Gross(1)	Gross(1)	Gross(1)
Development
	Gas(2)		19	1	3
	Oil(3)		61	—	—
	Abandoned(4)		31	—	—

		Total	111	1	3

(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, Desdemona and Corsicana Properties; chemical injection at the Nowata Properties; drilling and completing wells in the Barnett Shale formation of the Desdemona Properties; and initiating well workovers and return to production activities at the New Mexico Properties. These activities are discussed in greater detail at "Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Development Update."

Delivery Commitment

At June 30, 2007, 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 Agreement. 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 4 to the consolidated financial statements regarding the mortgages that we have granted under the Credit Agreement 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 in the operation of our business.

Acquisitions

We regularly pursue and evaluate acquisition opportunities (including opportunities to acquire oil and natural gas properties or 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 may take the form of internal financial and oil and natural gas property analysis, preliminary due diligence, the submission of an indication of interest, preliminary negotiations, 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 acquisition of producing properties and oil and natural gas leases, and obtaining goods, services and labor. Many of our competitors have substantially greater financial and other resources. 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 several independent purchasers. During the years ended June 30, 2007, 10% or more of our total revenues were attributable to four customers representing 36%, 18%, 17% and 16% of total operating revenue, respectively. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. 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. All transportation costs are accounted for as a reduction of oil and natural gas sales revenue.

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 sale of crude oil, natural gas and gas liquids within its jurisdiction.

Transportation and Sale of Natural Gas

Our natural gas sales were approximately 44% of our total sales during the year ended June 30, 2007. 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 any natural gas operations.

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 by prior owners or operators of properties in which we own interests.

Our insurance policies provide for $1,000,000 general liability coverage for bodily injury and property damage including pollution, underground resources, blow out and cratering. We also have $25,000,000 umbrella coverage in excess of the general liability, including pollution and automobile liability. There is a $3,000,000 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.

Occupational Safety Regulation

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

Federal, State or Native American Lease

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 6, 2007, we and our wholly-owned subsidiaries had 114 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 excellent.

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 April 20, 2011. See Note 12 to the 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 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 Securities and Exchange Commission.

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 recover 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.

"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.

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

"MCFPD." Mcf per day.

"MMBOE." One million BOE.

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

"MMCFPD." MMcf per day.

"NET ACRES." The sum of the fractional working or any type of royalty interests owned in gross acres.

"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.

"PROVED DEVELOPED 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.

"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.

"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, SP FLOODING, ALKALINE SURFACTANT-POLYMER FLOODING AND 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, much like soap in a greasy dish pan.

"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.

"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.

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

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

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the 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 oil and natural gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market and political uncertainty and other 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 oil and natural gas price movements with any certainty. Declines in 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, the 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. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment 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. The transportation and storage of refined products include the risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies and private parties for natural resources damages, personal injury, or property damages and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined and unrefined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. As a result, we may incur substantial expenditures and/or liabilities to third parties or governmental entities which could have a material adverse effect on us.

The oil and natural gas industry is capital intensive, and we may not be able to raise the necessary capital in the future.

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

Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from bank borrowings and sales of our equity securities. In addition, we may consider selling additional non-core assets to raise additional operating capital.

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 borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility 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 undertake or complete future drilling 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, and there can be no assurance as to the availability of any additional financing 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.

Prior to the Davenport Merger in May 2004, we were inactive with no significant operations. In connection with the Davenport Merger, we decided to focus our business on the acquisition of attractive crude oil and natural gas prospects, and the exploration, development and production of oil and natural gas on these prospects. Since that time, we have acquired rights in oil and natural gas properties and undertaken certain exploitation and other activities. However, we do not have a long operating history in our current business. Although we are in the process of initiating three waterfloods and an alkaline-surfactant project, we have not completed any new waterflooding or EOR technologies on our own on any of our properties. 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. You must consider our business and prospects in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. For our business plan to succeed, we must successfully undertake most of the following activities:

•: Find and acquire rights in attractive oil and natural gas properties;
•: Develop our oil and natural gas properties, including the successful application of EOR technologies and procedures, to the point at which oil and natural gas are being produced in commercially viable quantities;
•: Contract with third party service providers regarding services necessary to develop our oil and natural gas wells;
•: Contract with transporters and purchasers of our commercial production of oil and natural gas;
•: 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;
•: 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 undertake successfully most of the activities described above could materially and adversely affect our business, prospects, financial condition and results of operations. In addition, there can be no assurance that our exploitation and production activities will produce oil and natural gas in commercially viable quantities. There can be no assurance that sales of our oil and natural gas production will ever generate sufficient revenues or that we will be able to sustain profitability in any future period.

If we cannot obtain sufficient additional capital when needed, we will not be able to continue with our business strategy. In addition, significant infusions of additional capital may result in dilution to your ownership and voting rights in our securities.

Our business strategy is to acquire interests in mature oil fields with established reserves that have declined to marginal production levels, but possess significant remaining upside exploitation potential, and implement various secondary and tertiary enhanced oil recovery operations. We are focused on acquiring undervalued properties that feature enhanced recovery opportunities. As we continue to find acquisition candidates, we may require additional capital to finance the acquisitions as well as to conduct our EOR operations. We may not be able to obtain additional financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the additional 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 regardless of whether or not we generate profits or cash flows from our business activities.

Equity financing may result in dilution to existing stockholders and may involve securities that have rights, preferences, or privileges that are senior to our common stock.

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

This prospectus contains estimates of our proved reserves. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development 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 87% of our total proved reserves as of June 30, 2007 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

Approximately 83% of our total proved reserves as of June 30, 2007 are undeveloped and approximately 4% are developed non-producing. 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 at the time periods we have planned, at the costs we have budgeted, or at all. The aggregate estimated development costs for our proved undeveloped reserves are approximately $325,000,000 as of June 30, 2007.

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

On May 28, 2004, we acquired Davenport Field Unit, which owned a 100% working interest in certain oil, natural gas and mineral leasehold estates and personal property related such leasehold estates located in Lincoln County, Oklahoma covering approximately 2,178 acres. On September 14, 2004, we acquired the Nowata Properties comprised of more than 220 oil and natural gas producing wells on 2,601 acres of land in Nowata County, Oklahoma. On March 29, 2005, we acquired Square One, pursuant to which we own a 100% working interest in 10,300 acres of mature oil fields in central Texas. On November 29, 2005, we acquired all of the outstanding common stock of WO Energy, pursuant to which we own oil and natural gas properties on approximately 20,000 acres in Carson, Gray and Hutchinson counties located in the Texas panhandle with 480 producing wells, 40 water disposal

wells and 380 idle wells. On April 28, 2006, our wholly owned subsidiary Pantwist, LLC acquired additional oil and natural gas properties in the Texas panhandle, which properties cover approximately 9,700 acres with 167 wells. On March 30, 2007, our wholly owned subsidiary, Cano Petro of New Mexico, Inc., acquired additional oil and natural gas properties in New Mexico, which properties cover approximately 20,000 acres. Our operational strategy is to implement waterflood and EOR techniques. The performance of waterflood and EOR techniques is often difficult to predict, takes an extended period of time from first investment until actual production and we may not achieve the anticipated production growth from properties we acquire.

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

Our recent growth is due in part to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. We expect acquisitions will 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 a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. 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 or be able to complete such acquisitions on acceptable terms.

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 with development and exploration potential 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 as efficiently as in our prior acquisitions.

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

We do not always encounter commercially productive reservoirs through our drilling operations or our application of waterflooding or EOR techniques. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The engineering data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may 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 return a profit after drilling, operating and other costs or our application of waterflooding or EOR techniques is not successful. Further, our drilling and other operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•: unexpected drilling conditions;

•: title problems;
•: pressure or irregularities in formations;
•: equipment failures or accidents;
•: adverse weather conditions; and
•: increases in the costs of, or shortages or delays in the availability of, chemicals, drilling rigs and equipment.

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; Morris B. Smith, Senior Vice President and Chief Financial Officer; Patrick McKinney, Senior Vice President—Engineering and Operations; and Michael J. Ricketts, Vice President and Principal Accounting Officer. All of these individuals are integral parts of our daily operations. We have employment agreements with Messrs. Johnson, Smith, McKinney, and Ricketts. We do not maintain any key life insurance policies for any of our executive officers or other personnel. Although, to our knowledge, none of our senior management currently has any plans to retire or leave our company in the near future, the loss of any of them 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, which makes it difficult to conduct profitable operations.

Our competitors include major 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 large, well-established companies and have substantially larger operating staffs and greater capital resources than we do. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, 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.

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

We may depend on our revolving credit facility for future capital needs. As required by our revolving credit facility with our bank lenders, we have pledged substantially all of our oil and natural gas properties as collateral to secure the payment of our indebtedness. The revolving credit facility restricts 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. The revolving credit facility prohibits 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 economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the revolving credit facility impose on us. 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 the revolving credit facility. 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, it may not be on terms that are acceptable to us.

In addition, the revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders, based upon projected revenues 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 the revolving credit facility.

Derivative activities create a risk of financial loss.

Pursuant to the terms of our revolving credit facility, we are parties to oil and natural gas price risk management arrangements with respect to a portion of our expected production. We purchase floors that generally result in minimum price received by us for a portion of our production over a specified time period. We have the right to receive from the counterparty, the excess of the fixed price specified in the contract over a floating price based on a market index, multiplied by the quantity identified in the derivative contract. These transactions may expose us to the risk of financial loss if the counterparty to our future contracts fail to perform under the contracts.

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, 2007, we concluded that we maintained effective internal control over financial reporting as of June 30, 2007, 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 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 as a result of a blow-out. We have a "Owned-Hired and Non-Owned" Commercial Automobile liability limit of $1,000,000. We also have secured $25,000,000 umbrella coverage in excess of the general liability and automobile liability. There is a $3,000,000 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.

There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations and incurrence of additional debt.

Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.

Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expense, all of which could have a material adverse effect on our financial condition and operating results.

Terrorist activities may adversely affect our business.

Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Part of our business is seasonal in nature which may affect the price of our oil and natural gas.

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. As a result, our results of operations may be adversely affected by seasonal conditions.

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, if a "triggering event" occurs, the holders of our Series D Convertible Preferred Stock will have the right to require us to redeem their preferred stock at a minimum price of at least 125% of the $1,000 per share stated value plus certain 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 and as due pursuant to the terms of the Series D Convertible Preferred Stock or any documents related to the sale and registration rights of the Series D Convertible Preferred Stock, common stock and warrants;
•: certain actions are taken by us or third parties 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 regarding the Series D Convertible 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 upon an occurrence of a "triggering event."

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

We are subject to several lawsuits 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 are defendants in several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas. The alleged damages include damage to land and livestock, remedial expenses and claims relating to wrongful death. We entered into a Settlement Agreement with our insurance carrier pursuant to which we received $6,699,827 in exchange for releasing the insurance carrier from any future claims. This amount may not be sufficient to cover all of our litigation expenses and all the alleged damages.

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. Further, the limited market for our shares will make our price more 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, 2007, the market price for our common stock has ranged from $0.45 to $10.65. On September 6, 2007, our closing price on AMEX was $6.03. Any future market price for our shares may continue to be very volatile. This price volatility may make it more difficult for you to sell shares when you want at prices you find attractive. We do not know of any one particular factor that has caused volatility in our stock price. However, 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 market 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 AMEX, our common stock may be delisted which would have a material adverse effect on the price of our common stock.

Our common stock was listed on AMEX on May 5, 2005 under the symbol "CFW." In order for our securities to be eligible for continued listing on 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 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.

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

The Securities and Exchange Commission 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 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 Securities and Exchange Commission 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
•: that 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 these analysts. Furthermore, there are many large, well-established, publicly traded companies active in our industry and market, which may mean that it is less likely that we will receive widespread analyst coverage. If one or more of the analysts who do cover us downgrade 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, the available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our revolving credit facility and our Series D Convertible Preferred Stock.

Provisions in our corporate governance and loan documents, the terms of our Series D Convertible 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 Series D Convertible Preferred Stock, our bylaws, our loan documents 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 Series D Convertible Preferred Stock permit the holders of such preferred stock the right to have their Series D Convertible Preferred Stock redeemed upon a "change of control." In addition, the terms of our Series D Convertible 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 Series D Convertible Preferred Stock and the holders of a majority of our Series D Convertible Preferred Stock approve such assumption and the successor entity is publicly traded on the 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 Series D Convertible Preferred Stock, we are authorized to issue additional shares of preferred stock. Subject to the terms of the Series D Convertible Preferred Stock and our certificate of incorporation, our board of directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the board of directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:

•: restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;
•: dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;
•: dilution of the equity interest of common stock and other series of preferred stock; and
•: limitation on the right of holders of common stock and other series of preferred stock to share in Cano's assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.

The terms of our Series D Convertible 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 Series D Convertible Preferred Stock may be a 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 Series D Convertible Preferred Stock, the conversion price shall be adjusted downward which would further dilute our common stock holders upon conversion.

Our Series D Convertible 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 Series D Convertible 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 Series D Convertible Preferred Stock;
•: increase or decrease the number of authorized shares of Series D Convertible Preferred Stock;
•: create any class of preferred stock that has a preference over or is in parity with the Series D Convertible 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 Series D Convertible 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% on the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable Treasury regulations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties (see Items 1 and 2. Business and Properties)

Item 3. Legal Proceedings

Fire Litigation

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 W.O. 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.

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, has intervened in the suit joining the plaintiffs' request to terminate certain oil and natural gas leases and on January 26, 2007, Southwestern Public Service Company d/b/a Xcel Energy, intervened in the suit as an adverse party to all defendants, claiming that the fire that is subject of this lawsuit destroyed transmission and distribution equipment, including utility poles, lines and other equipment with an estimated loss of $1,876,000. By order dated March 7, 2007, the court granted defendants' motion to strike the intervention of Southwest Public Service Company d/b/a Xcel Energy.

On June 21, 2007, the Judge of the 100^th 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 has been appealed.

On April 28, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating Company, Ltd, and W.O. Energy, Inc. There are 43 plaintiffs and four groups of intervenors that 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.

The plaintiffs and intervenors (i) allege negligence, gross negligence, trespass and nuisance and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $11,297,684. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The case is set for trial on October 29, 2007. On May 21, 2007, the plaintiffs filed a first amended petition. In their amended petition, the plaintiffs assert an additional claim for res ipsa loquitor and also claim that the Company and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. Further, the First Amended Petition names eleven new plaintiffs to the suit. It omits the claims of three original plaintiffs who do not appear to have any claims currently pending against the Company. Five of the former plaintiffs have asserted claims in the matter styled Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating, Ltd, and W.O. Energy, Inc. (discussed below), while one of the plaintiffs has intervened in the matter styled

Southwestern Public Service Company d/b/a Xcel Energy v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd, and W.O. Energy, Inc. (also discussed below). Discovery in the suit is underway and the case is set for trial on October 29, 2007. On August 28, 2007, one of the intervenors, Travelers Lloyds Insurance Company, filed a Notice of Nonsuit requesting the court to sign an order dismissing its claims, which seek approximately $367,627 of total damages, without prejudice.

On April 10, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas, Case No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating Company, Ltd, and W.O. Energy, Inc. On May 1, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas, Case No. 1923, Chisum Family Partnership, Ltd. v. Cano, W.O. Energy of Nevada, Inc.; W. O. Operating Company, Ltd, and W.O. Energy, Inc. The plaintiffs in both cases 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.

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

On July 3, 2006, the following lawsuit was filed in the 31^st Judicial District Court of Roberts County, Texas, Case No. 1928, Rebecca Lee Martinez, et al v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc.; W. O. Operating Company, Ltd., and W.O. 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 undisclosed damages for the wrongful death of two individuals who they claim died as a result of the fire. Additional heirs and relatives of one of the decedents have intervened in this case seeking similar claims.

On August 9, 2006, the following lawsuit was filed in the 233rd Judicial District Court of Gray County, Texas, Yolanda Villareal, Individually and on behalf of the Estate of Gerardo Villareal v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd., and W.O. 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 undisclosed damages for the wrongful death of Gerardo Villareal who they claim died as a result of the fire. Relatives of Roberto Chavira have intervened in the case alleging similar claims regarding the death of Roberto Chavira.

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 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. This case is a refiling of the intervention which was struck by the court as described above.

The plaintiff alleges negligence and seeks $1,876,000 in damages for loss and damage to transmission and distribution equipment, utility poles, lines and other equipment. In addition, the plaintiff seeks reimbursement for its attorney's fees. On May 15, 2007, three new plaintiffs (one of which is a former plaintiff in the Adcock matter) intervened in the lawsuit and (i) allege negligence, gross negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $201,280. In addition, the intervenors seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors also claim that the Company and its subsidiaries are

jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.

On May 2, 2007, the following lawsuit was filed in the 84^th Judicial District Court of Hutchinson County, Texas, Case No. 37,619, Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. And W.O. Energy, Inc. Eleven plaintiffs claim 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 are former plaintiffs in the Adcock matter. The plaintiffs (i) allege negligence, gross negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $1,152,480. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claim that the Company and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.

Due to the inherent risk of litigation, the outcome of these cases is uncertain and unpredictable; however, at this time Cano management believes the suits are without merit and is vigorously defending itself and its subsidiaries.

Insurance Settlement

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, Plaintiff, vs. 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 and on September 18, 2006, the First Amended Complaint for Declaratory Judgment was filed with regard to the cases described above. Cano and its subsidiaries were served with the lawsuit between September 26-28, 2006.

On February 9, 2007, Cano and its subsidiaries entered into a Settlement Agreement and Release with the plaintiff pursuant to which in exchange for mutual releases, in addition to the approximately $923,000 that we have been reimbursed by plaintiff, the plaintiff agreed to pay to Cano within 20 business days of February 9, 2007 the amount of $6,699,827 comprised of 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, in accordance with the Credit Agreement (Note 4 to our consolidated financial statements), have been placed in a controlled bank account and the use of the proceeds is specified to pay attorney's fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation. Accordingly, our consolidated balance sheets reflect the $6,000,000 as restricted cash and a corresponding liability under deferred litigation credit. The remaining $699,827 was applied as a reduction to general and administrative expense for litigation expenses incurred.

Other

position or results of operations. None of our directors, officers or affiliates, owners of record or beneficially of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to our business or has a material interest adverse to our business.

Item 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, 2007.

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 American Stock Exchange ("AMEX") under the trading symbol "CFW." For the years ended June 30, 2006 and 2007, the following table sets forth the high and low sales prices per share of common stock for each quarterly period. On September 6, 2007, the closing sale price on the AMEX was $6.03.

	Fiscal 2007				Fiscal 2006
Fiscal Quarter	Fiscal 2007				Fiscal 2006
Fiscal Quarter	High		Low		High		Low
First Quarter Ended September 30	$	6.40	$	3.69	$	5.90	$	3.51
Second Quarter Ended December 31	$	5.80	$	3.90	$	8.40	$	4.14
Third Quarter Ended March 31	$	5.47	$	4.15	$	10.65	$	6.43
Fourth Quarter Ended June 30	$	6.47	$	4.40	$	8.66	$	4.09

Holders

As of September 6, 2007, our shares of common stock were held by approximately 250 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 6, 2007, there were approximately 4,300 beneficial holders who own 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 Agreement does not permit us to pay dividends on our common stock. In addition, the terms of our Series D Convertible Preferred Stock do not permit us to pay dividends on our common stock without the approval of the holders of a majority of the Series D Convertible Preferred Stock.

For the year ended June 30, 2007, the preferred dividend was $3,169,516, of which $1,746,923 pertained to holders of the PIK dividend option.

During the year ended June 30, 2007, 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.

During the quarter ended June 30, 2007, we did not repurchase any of our registered equity securities.

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 September 4, 2003 to June 30, 2007, assuming an initial investment of $100 and the reinvestment of all dividends, if any. Since Huron Ventures, Inc. (our predecessor company) filed a Form 10 SB to register common stock pursuant to Section 12(g) of the Securities Exchange Act of 1934 on September 4, 2004, we used a starting point beginning with September 4, 2003 for the data presented below.

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, 2007 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,
			2007			2006			2005			2004			2003(1)
Operating Revenues:
	Crude oil and natural gas sales		$	28,353,026		$	15,860,562		$	3,764,015		$	7,958		$	—
Operating Expenses:
	Lease operating expenses			10,885,393			6,240,986			2,068,881			44,305			—
	Production and ad valorem taxes			2,465,191			1,153,775			223,566			616			—
	General and administrative			12,755,524			7,622,508			4,753,609			341,020			12,418
	Accretion of asset retirement obligations			140,129			90,492			48,204			690			—
	Depletion and depreciation			4,305,696			1,847,217			370,899			4,533			—

		Total operating expenses		30,551,933			16,954,978			7,465,159			391,164			12,418

Loss from operations:				(2,198,907	)		(1,094,416	)		(3,701,144	)		(383,206	)		(12,418	)

Other income (expenses):
Unrealized loss on hedge contracts				(1,810,000	)		(3,245,588	)		—			—			—
Realized gain on hedge contracts				962,559			540,871			—			—			—
Interest expense				(2,559,619	)		(2,426,321	)		—			—			—
Interest income and deductions, net				253,026			124,467			11,661			—			—

		Total other income (expenses)		(3,154,034	)		(5,006,571	)		11,661			—			—
Loss from continuing operations before income tax benefit				(5,352,941	)		(6,100,987	)		(3,689,483	)		(383,206	)		(12,418	)
Income tax benefit				1,918,551			3,771,083			—			—			—

Loss from continuing operations				(3,434,390	)		(2,329,904	)		(3,689,483	)		(383,206	)		(12,418	)
Income on disposal of discontinued operations, net:				2,644,534			485,480			716,341			—			3,139,167
Preferred stock discount							—			416,534			—			—
Preferred stock dividend				3,169,516			—			—			—			—

Net income (loss) applicable to common stock:
	Continuing operations			(3,434,390	)		(2,329,904	)		(3,689,483	)		(383,206	)		(12,418	)
	Discontinued operations			2,644,534			485,480			716,341			—			3,139,167
Net income (loss) per share—basic and diluted			$	(0.13	)	$	(0.08	)	$	(0.29	)	$	(0.05	)	$	4.77

Weighted average common shares outstanding
	Basic and diluted			30,758,441			22,364,099			11,839,080			7,311,505			655,778

CASH FLOW DATA:
Cash flow provided by (used in):
	Operating activities			2,658,407		$	(6,083,774	)	$	(501,035	)	$	(633,927	)		(9,487	)
	Investing activities			(39,854,248	)		(78,365,354	)		(10,726,180	)		(1,248,858	)		7,987
	Financing activities			38,670,280			84,948,298			9,797,425			3,438,064			21,500
BALANCE SHEET DATA:
Cash and cash equivalents				2,119,098		$	644,659		$	145,489		$	1,575,279			20,000
Total assets				201,469,244			146,948,731			17,578,420			3,340,564			20,000
Long-term debt				33,500,000			68,750,000			—			—			—
Temporary equity—Series D convertible preferred stock and paid-in kind dividend; liquidation preference is $50,862,925				47,596,061			—			—			—			—
Stockholders' equity				68,861,235			40,636,233			15,390,949			2,932,765			17,339

(1): We were incorporated as Huron Ventures, Inc. on May 29, 2003, and on June 3, 2003, we became a parent holding company of Calypso Merger, Inc., the survivor of a merger of it and Calypso Enterprises, Inc. Calypso Enterprises, Inc. is a predecessor of us for accounting purposes and its results of operations from July 1, 2002 until June 3, 2003 are included in our financial statements covering such periods.

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 that could cause the actual results, performance or achievements to differ materially from our expectations are disclosed in this 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 expressly qualified in their entirety by the Cautionary Statements.

Overview

Introduction

We are a growing independent oil and natural gas company that is actively pursuing waterflooding and enhanced oil recovery techniques to increase production and reserves at our existing properties and properties acquired in the future. Our primary focus is crude oil and our target acquisitions are onshore U.S. properties. Our focus on domestic, mature oil fields eliminates exploration risks and uncertainties of international sources. We use waterflooding and enhanced oil recovery methods, such as alkaline/ surfactant/ polymer technology.

During our first two years of operations through June 30, 2006, our primary focus was to achieve growth through acquiring existing, mature oil and natural gas fields. In March 2007, we acquired Permian Basin oil and natural gas properties located in New Mexico. We believe the portfolio of oil and natural gas properties that we have acquired thus far provides ample opportunities to apply our operational strategy.

As of June 30, 2007, we had proved reserves of 66,720 MBOE, of which 8,454 MBOE were proved producing, 2,843 MBOE were proved non-producing, and 55,423 MBOE were proved undeveloped.

During the fiscal year ended June 30, 2007, our primary emphasis was to achieve growth by developing our existing oil and natural gas properties through development activities such as waterflooding and EOR technology. We will continue to evaluate potential acquisition targets that are consistent with our operational strategy. These development activities are more clearly defined later in the next section titled "Capital Development Update."

As discussed in greater detail below under "Liquidity and Capital Resources", during September 2006, we issued preferred and common stock that had net proceeds of $75.5 million. These proceeds were used to repay long-term debt of $68.75 million, and the remainder was used to provide working capital and for general corporate purposes, including the funding of our fiscal 2007 capital budget, as discussed below. Our outstanding subordinated debt totaling $15 million, with an interest rate of 12.74%, has been permanently retired. The Credit Agreement is our only source of long-term debt.

Capital Development Update

For the year ended June 30, 2007 ("2007 Fiscal Year"), we incurred $53 million of capital expenditures. Of the $53 million, $45 million was incurred ($40 million spent) to implement developmental projects at our existing fields to increase reserves; convert existing proved undeveloped reserves to proved producing reserves; and increase production. The remaining $8 million pertained to our acquisition of New Mexico Properties, as discussed below. The $53 million was financed by the September 2006 financing and Credit Agreement, as discussed below under "Liquidity and Capital Resources."

For the year ending June 30, 2008 ("2008 Fiscal Year"), we have a capital development budget of $57 million, which is further discussed under "2008 Planned Capital Expenditures." The status of our capital development activity during Fiscal Year 2007 and planned activity during 2008 Fiscal Year is summarized as follows:

Panhandle Properties. Proved reserves as of June 30, 2007 attributable to the Panhandle Properties are 35,547 MBOE, of which 3,397 MBOE are proved producing, 32,150 MBOE are proved undeveloped and none of which is proved non-producing. Current production is approximately 650 BOEPD. We are progressing with the execution of our waterflood development plan at the Cockrell Ranch Unit of the Panhandle Field. We were granted our Phase I waterflood injection permits from the Texas Railroad Commission in February 2007. We have had two drilling rigs running in the field since April 2007 and have drilled and completed 60 waterflood replacement wells in our Phase I and Phase II development patterns. 10 replacement wells remain to be drilled to complete Phase III. We commenced water injection into the Cockrell Ranch Unit waterflood at the Panhandle field on July 5, 2007. At the present time, we have a total of 34 injection wells water moving into the Brown Dolomite formation at roughly 24,000 barrels per day. As we continue bringing additional injection wells on, we anticipate achieving the full 75 well injection pattern by mid-October 2007 with a maximum injection rate of 52,500 barrels per day. Preliminary response from the waterflood is still anticipated in December 2007. Full waterflood development over the remaining 11,000+ net acres of the Panhandle Properties is anticipated once the initial response data is available.

Desdemona Properties. Proved reserves as of June 30, 2007 attributable to the Desdemona Properties are 11,851 MBOE, of which 711 MBOE are proved producing, 1,175 MBOE are proved non-producing and 9,965 MBOE are proved undeveloped. Current production is approximately 205 BOEPD.

Desdemona Properties—Waterflood. We have drilled and completed 11 required replacement wells to initiate the development of the Duke Sand Waterflood at Desdemona. Procurement and infrastructure development of the waterflood facilities is 100% complete. We have received preliminary approval of our waterflood permit from the Texas Railroad Commission and expect to initiate water injection within the next 30 days. We anticipate an initial waterflood response in the first calendar quarter of 2008.

Desdemona Properties—Barnett Shale. We have successfully drilled and completed wells in the Barnett Shale formation in this field, located some 50 miles west of established Barnett Shale production in the Ft. Worth Basin. We have drilled fifteen vertical wells to delineate the lateral extent of the Barnett Shale formation within the roughly 11,000 acres of our Desdemona Field. Currently, the Barnett Shale vertical wells are averaging 700 MCFPD of total gas production. The results of the vertical well test program have provided encouraging results that have allowed us to initiate our Horizontal Well Development Program in the field.

Based on our vertical test results and analogs, it is internally estimated Cano has 80 total horizontal locations on roughly 120 acre spacing, of which 76 future horizontal locations were considered for proved undeveloped reserves. We booked proved reserves of 6.8 MMBOE for the

Barnett Shale play at June 30, 2007. Of this amount, 6.0 MMBOE was proved undeveloped. We also have Marble Falls formation re-completion potential in all of our vertical and horizontal Barnett Shale wells. Based on the three existing Marble Falls re-completions producing in the field, we booked 4.0 MMBOE of proved reserves, of which 3.9 MMBOE was proved undeveloped in the Marble Falls formation. We have drilled and completed 4 horizontal wells out of the announced FY 2008 Budget 24 horizontal wells in the field. The four new wells are currently flowing back load and are under evaluation. In response to currently low natural gas prices, we have elected to defer the drilling program in the Barnett Shale. Of the remaining capital amount of roughly $15 million committed to this program, roughly $5 million will be re-directed to the New Mexico Properties (as discussed below) and the balance of $10 million will committed to the Barnett Shale program once natural gas prices improve.

Nowata Properties. Proved reserves as of June 30, 2007 attributable to the Nowata Properties are 1,687 MBOE, all of which are proved producing. As a result of prior waterflood operations on the Nowata Properties, current net production is approximately 200 BOEPD. We completed the budgeted workovers to return 15 wells to production in the Nowata field to optimize the existing waterflood pattern. Our tertiary recovery pilot project at the Nowata Field is underway. The ASP pilot plant, associated equipment and supplies were installed and tested during July and August 2007. ASP Pilot start-up operations will begin in mid-September 2007. Response is anticipated in the first calendar quarter of 2008.

Davenport Properties. Proved reserves as of June 30, 2007 attributable to the Davenport Properties are 1,488 MBOE, of which 552 MBOE are proved producing, 936 MBOE are proved non-producing and none of which are proved undeveloped. As a result of ongoing waterflood operations on the Davenport Properties, current production is approximately 80 BOEPD. We completed workovers to return twelve wells to production and are awaiting final regulatory approval to activate eleven injection wells to optimize the existing waterflood pattern at this field. Initial results of the wells returned to production have been encouraging and production increases have exceeded expectations. Contingent upon successful laboratory studies, we anticipate initiating an ASP Pilot project during our fiscal year ending June 30, 2009.

Corsicana Properties. The Corsicana Properties were the subject of a proved surfactant-polymer chemical injection pilot in the 1980s and contain proved reserves as of June 30, 2007 of 205 MBOE, of which 108 MBOE are proved non-producing and 97 MBOE are proved undeveloped. We have drilled and completed 16 pattern replacement wells and plan to reinstate a prior waterflood in this field. During June 2007, we received the required permits to inject water. We are planning to reinstate the prior waterflood in September 2007. As we previously mentioned, we have been pleased with the remaining oil saturations in this field and coupled with the prior successful polymer pilot in this field in the 1980's we believe this field is a prime ASP candidate. Once the waterflood response and laboratory results are analyzed, we anticipate evaluating an ASP Pilot in the field in calendar year 2008.

Pantwist Properties. Proved reserves as of June 30, 2007 attributable to the Pantwist Properties are 6,829 MBOE, of which 1,883 MBOE are proved producing, 4,946 MBOE are proved undeveloped and none of which are proved non-producing. Current production is approximately 350 BOEPD. We anticipate implementation of waterflood injection operations during 2011 and 2012 calendar years.

New Mexico Properties—New Acquisition. In addition to the capital spending activities previously discussed, we completed an acquisition on March 30, 2007, with an effective date of February 1, 2007, to acquire certain oil and gas properties in the Permian Basin for approximately $8.4 million, after purchase price adjustments. Proved reserves as of June 30, 2007 attributable to the New Mexico Properties are 9,112 MBOE, of which 224 MBOE are proved producing, 8,264 MBOE are proved undeveloped and 624 MBOE are proved non-producing. Current production is approximately 50 BOEPD. These properties include roughly 20,000 acres and 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. We believe that the Cato Field is the largest San Andres field in the Permian Basin that has never been flooded. There were two successful waterflood pilots conducted in the field in the 1970's by Shell and Amoco. This field was unitized by Kelt Oil in 1990, secondary recovery permits are in place and there now exists a water supply pipeline to an adjacent field 1.5 miles away. Moreover, this field is a very viable CO-2 tertiary flood candidate with a CO-2 pipeline located four miles from the site. We initiated well workovers and a return to production program in May 2007. We have worked over 20 idle wells and have returned 10 wells to production to date. We plan to return between 60 - 80 wells to production during the course of the year. We have deployed re-frac stimulations on four wells in the field. Production responses of between 15 - 25 BOEPD per well have been achieved. It is our goal to re-frac up to 25 of the return to production wells during the course of the year. Additionally, one drilling rig has been contracted to drill 11 new 40-acre spaced wells in areas of the field that have not been developed. The first well is expected to spud by October 2007. Another drilling rig has been contracted to drill 21 new 20-acre infill wells in an area of the field that had a prior waterflood pilot. The first well is expected to spud by November 2007. Initiation of Phase I of the waterflood at Cato is scheduled for second calendar quarter of 2008.

Rich Valley Field. 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 $6.9 million cash. The agreement had an effective date of April 1, 2007. All of the funds received were used to reduce the outstanding balance under the Credit Agreement discussed below. As of April 1, 2007, the assets of the Rich Valley Properties totaled $3.3 million, of which $3.2 million represented the oil and gas properties, net. We recognized a $3.8 million pre-tax gain on the sale of the Rich Valley Properties.

Industry Conditions

Our Strategy

•: Acquire Strategic Assets. We seek to acquire low-cost assets with a high ratio of non-proven or proved undeveloped reserves suitable for waterflood and EOR techniques, primarily in the onshore United States. We believe we have acquired an attractive portfolio of assets to implement our business plan. We will continue to selectively target potential acquisition candidates in a disciplined manner, which involves being financially prudent and acquiring assets that meet our engineering and operational standards. We focus on U.S. operations. Accordingly, we are not subject to geopolitical uncertainties, dependence on foreign sources and other issues related to overseas operations.
•: No Exploration Risk. Our portfolio is comprised of mature fields with proven reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on exploration drilling and the high degree of speculation in making new discoveries.

•: Exploit and Develop Existing Properties. We intend to add proved reserves to, and increase production from, our existing properties through the application of advanced technologies, including water, gas or chemical flooding and other EOR techniques. We believe that our management team has a proven track record of exploiting underdeveloped properties to increase reserves and cash flow.
•: Maintain a Low Cost Structure. We intend to maintain a low cost structure through maintaining efficient operations and operating control. We intend to be the working interest operator in a high proportion of our properties. This allows us to exercise more control over expenses, capital allocation, and the timing of development and exploitation activities in our fields. It also enables us to implement controls over our costs to ensure prudent expenditures. Further, we employ engineering and geological consultants to aid in evaluating the economic merits of drilling plans and potential acquisitions on a case-by-case basis rather than staffing these positions, enabling us to maintain low fixed costs.

Liquidity and Capital Resources

Our primary sources of capital and liquidity have been issuance of equity securities, borrowings under credit facilities with lenders, and cash flows from operating activities.

September 2006 Financing

On September 6, 2006, we sold in a private placement 49,116 shares of Series D Convertible Preferred Stock at a price of $1,000.00 per share and 6,584,247 shares of common stock at a price of $4.83 per share, the three day average closing price of the stock prior to the execution of the definitive agreements, plus a warrant component. The preferred stock has a 7.875% dividend and features a paid-in-kind ("PIK") provision that allows, at the investor's option, the investor to receive additional shares of common stock upon conversion for the dividend in lieu of a cash dividend payment. Holders of approximately 55% of the preferred stock chose the PIK dividend option. The preferred stock is convertible to common stock at a price of $5.75 per share and the common stock was subject to 25% warrant coverage at an exercise price of $4.79 per share. If any Series D Convertible Preferred Stock remains outstanding on September 6, 2011, we are required to redeem the Series D Convertible Preferred Stock for a redemption amount in cash equal to the stated value of the Preferred Stock, plus accrued dividends and PIK dividends. Gross proceeds from the transactions were $80.9 million, of which $49.1 million was attributable to the preferred stock, and $31.8 million was attributable to the common stock and warrants. Net proceeds were $75.5 million after deducting for issuance costs of $5.4 million.

The warrant component totals 1,646,061 common shares and is exercisable at $4.79 per share. The exercise period commenced on March 5, 2007 and expires on March 6, 2008.

For the year ended June 30, 2007, the preferred dividend was $3,169,516, of which $1,746,923 pertained to holders of the PIK dividend option.

Cash proceeds from the September 2006 financing were used to repay long-term debt of $68.75 million (see Note 4 to the consolidated financial statements), for general corporate purposes and to fund our capital expenditures as previously discussed. The long-term debt consisted of amounts due under the Credit Agreement and subordinated credit agreement of $53.75 million and $15.0 million, respectively. Due to repaying the $15.0 million outstanding balance on the subordinated credit agreement, this debt facility was permanently retired.

Credit Agreement

On November 29, 2005, we entered into a $100 million credit agreement ("Credit Agreement") with the lenders led by Union Bank of California, N.A., as administrative agent and as issuing lender. During the quarter ended March 31, 2006, Natixis was named as a lender via an amendment to the Credit Agreement. The maturity date is November 29, 2009.

At June 30, 2007, we had $33.5 million outstanding under our Credit Agreement. As discussed in Note 4 to the consolidated financial statements, on September 7, 2007, our lenders approved an increase in the borrowing base to $60.0 million. At September 6, 2007, we had $41.5 million outstanding under our Credit Agreement. Pursuant to the terms of the Credit Agreement, the borrowing base is based on our proved reserves and is redetermined every six months with one additional redetermination possible during the six month periods between scheduled redeterminations.

Subject to certain restrictions, the Credit Agreement permits the issuance of convertible notes and equity with an optional redetermination of the borrowing base upon such issuance. If we are not in default under the Credit Agreement, we may make interest payments on any convertible notes and dividend payments on any preferred equity securities.

The Credit Agreement provides that we must comply with certain covenants for Leverage and Interest Coverage Ratios. These ratios are discussed in greater detail in Note 4 to the consolidated financial statements. We were in compliance with these ratios as of June 30, 2007.

At our option, interest is based either (i) on the prime rate plus the applicable margin ranging up to 1.00% based on the utilization level or (ii) on the LIBOR rate applicable to the interest period plus the applicable margin ranging from 1.75% to 2.50% based on the utilization level. At June 30, 2007 and 2006, the interest rate was 7.46% and 8.49%, respectively. At September 6, 2007, the interest rate was 7.97%. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.

The outstanding principal is due on or before November 29, 2009 unless pursuant to the terms of the Credit Agreement, specific events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults by us, breaches of representations and warranties and covenants by us, our insolvency, a "change of control" of our business as described in the Credit Agreement and a "material adverse change" as described in the Credit Agreement.

related to oil and natural gas properties unless with regard to new oil and natural gas properties, such properties are mortgaged to Union Bank of California, N.A., as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage in favor of Union Bank of California, N.A., as administrative agent; and (vi) subject to specific exceptions, entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.

In addition, we are required to enter into financial contracts to hedge our exposure to commodity price risk associated with expected oil and natural production. The Credit Agreement requires financial hedge contracts to cover no less than 50% and no more than 80% of the production volumes attributable to our proved reserves. Our financial hedge contracts are further discussed in Note 5 of the consolidated financial statements.

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

Cash Flows from Operating Activities and Other Capital Resources

At June 30, 2007, our cash balance was $2.1 million. We had cash provided by operating activities of $2.7 million during 2007 Fiscal Year, which was an improvement of $8.8 million as compared to the $6.1 million used in operations for 2006 Fiscal Year. The $8.8 million improvement is largely due to improved earnings as discussed under "Results of Operations—Years Ended June 30, 2007, 2006 and 2005" and reduced expenditures for commodity derivatives. At June 30, 2007, we had unused borrowing capacity of $10.5 million. The average interest rate of our debt was 7.46% at June 30, 2007. These results included net proceeds of $6.9 million that we received for the sale of the Rich Valley Properties, as previously discussed.

We believe the combination of cash on hand, cash flow generated from operations, strong commodity prices, available debt of $18.5 million under our Credit Agreement, and access to the capital markets for any future public or private issuances of debt or equity issuances should be sufficient to finance our working capital needs and $57 million capital expenditure program for 2008 Fiscal Year as further discussed below, in the section titled "2008 Planned Capital Expenditures." However, no assurance may be given that we will be successful in improving our operating results, the eventual success of our field developmental activities during the next twelve months or that we can successfully access capital markets for debt or equity issuances.

2008 Planned Capital Expenditures

For 2008 Fiscal Year we have a capital development budget of $57 million. We plan to spend approximately $20 to $25 million during the six months ended December 31, 2007 and the remaining amount during the six months ended June 30, 2008. As discussed under "Capital Development Update," the expenditures will primarily focus on completion of the Phase I waterflood development at the Panhandle Properties, initiate well workovers and a return to production of the New Mexico Properties, continued drilling in the Barnett Shale and completion of the ASP injection at the Nowata Properties.

Results of Operations—Years Ended June 30, 2007, 2006 and 2005

Overall

For the 2007 Fiscal Year, we had a loss applicable to common stock of $4.0 million, which is $2.2 million higher as compared to the $1.8 million loss applicable to common stock for year ended June 30, 2006 ("2006 Fiscal Year)."

For the 2006 Fiscal Year, we had a loss applicable to common stock of $1.8 million, which is $1.6 million lower as compared to the $3.4 million loss applicable to common stock incurred for the year ended June 30, 2005 ("2005 Fiscal Year").

The following table summarizes the differences between the years ended June 30, 2007, 2006 and 2005.

										Increase (Decrease)
	Fiscal Year Ended June 30,									Increase (Decrease)
Amounts in $millions	Fiscal Year Ended June 30,									2007 v. 2006			2006 v. 2005
Amounts in $millions	2007			2006			2005			2007 v. 2006			2006 v. 2005
Results of continuing oil and gas producing operations, excluding unrealized loss on commodity derivatives	$	11.6		$	7.1		$	1.1		$	4.5		$	6.0
Income from discontinued operations		2.6			0.5			0.7			2.1			(0.2	)
Less the following items:
General and administrative		12.8			7.6			4.8			5.2			2.8
Interest expense, net		2.3			2.3			—			—			2.3
Deferred income tax benefit		(1.9	)		(3.8	)		—			1.9			(3.8	)
Preferred stock dividend		3.2			—			—			3.2			—
Preferred stock discount		—			—			0.4			—			(0.4	)
Unrealized loss on commodity derivatives		1.8			3.3			—			(1.5	)		3.3

Net loss applicable to common stock	$	(4.0	)	$	(1.8	)	$	(3.4	)	$	(2.2	)	$	1.6

Results of oil and natural gas producing operations consist of operating revenues plus realized gain on commodity derivatives less lease operating expenses, production taxes, accretion of asset retirement obligations, and depletion and depreciation. The income from the discontinued operations pertains to the sale of our Rich Valley Properties, as further discussed in Note 6 to the consolidated financial statements.

2007 Fiscal Year results of continuing oil and gas producing operations is $4.5 million higher than 2006 Fiscal Year primarily due to:

•: Including a full twelve months of operating results from the Panhandle and Pantwist Properties which contributed $4.2 million. The 2006 Fiscal Year operating results included seven months of Panhandle Properties and two months of Pantwist Properties.
•: The remaining $0.3 million increase is attributed to improved operating results from our Davenport, Desdemona and Nowata Properties primarily due to increased sales.

2006 Fiscal Year is $6.0 million higher than 2005 Fiscal Year primarily due to:

•: Including seven months of operating results from the acquisition of the Panhandle Properties which contributed $3.1 million;
•: Including two months of operating results from the Pantwist Properties which contributed $0.9 million;

•: Including two months of operating results from the Nowata Properties which contributed $0.4 million; and
•: Improved operating results from our Davenport, Desdemona, and Nowata Properties, primarily due to higher crude oil and natural gas prices received and increased sales.

The other factors mentioned in the above table will be addressed in the following discussion.

Operating Revenues

The table below summarizes our operating revenues for the years ended June 30, 2007, 2006 and 2005.

								Increase (Decrease)
		Year Ended June 30,						Increase (Decrease)
		Year Ended June 30,						2007 v. 2006			2006 v. 2005
		2007		2006		2005		2007 v. 2006			2006 v. 2005
Operating Revenues		$	28,353	$	15,861	$	3,764	$	12,492		$	12,097
Sales:
	Oil (MBbls)		274		180		75		94			105
	Gas (MMcf)		1,313		531		18		782			513
	MBOE		493		268		78		225			190
Average Price
	($/Bbl)	$	61.95	$	63.32	$	48.98	$	(1.37	)	$	14.34
	($/Mcf)	$	8.67	$	8.38	$	5.37	$	0.29		$	3.01
	$/BOE	$	57.55	$	59.03	$	48.33	$	(1.48	)	$	10.70

2007 Fiscal Year v. 2006 Fiscal Year

The 2007 Fiscal Year operating revenues of $28.4 million represent an improvement of $12.5 million as compared to the 2006 Fiscal Year operating revenues of $15.9 million. The $12.5 million improvement is primarily due to:

•: Including a full twelve months of Panhandle and Pantwist Properties operating revenues, accounted for $11.4 million (197 MBOE) of the improvement. The 2006 Fiscal Year included seven months of Panhandle Properties' revenue and two months of Pantwist Properties' revenue.
•: Increased revenues from the Desdemona Properties ($0.5 million of revenue and 15 MBOE of sales) primarily due to increased natural gas sales from our development of the Barnett Shale formation, as previously discussed under "Capital Development Update."
•: Increased production from the Davenport and Nowata Properties ($0.4 million and 9 MBOE of sales).
•: Production from the recent acquisition, effective April 1, 2007, of our New Mexico Properties ($0.2 million and 4 MBOE of sales).

2006 Fiscal Year v. 2005 Fiscal Year

The 2006 Fiscal Year operating revenues of $15.9 million represent an improvement of $12.1 million as compared to the 2005 Fiscal Year of $3.8 million. The $12.1 million improvement is primarily attributable to:

•: Including seven months of operating revenue from the Panhandle Properties ($7.9 million of revenue and 139 MBOE of sales);
•: Including two months of operating revenue from the Pantwist Properties ($1.5 million of revenue and 24 MBOE of sales);

•: Including an additional two months of operating revenue from the Nowata Field ($0.8 million of revenue and 12 MBOE of sales);
•: The higher prices received for crude oil and natural gas sales; and
•: Increased sales of 15 MBOE from the other fields.

The average price we received for crude oil sales is generally at or above posted prices in the field. The average price we receive for natural gas sales is approximately the market (indexed) price less marketing and other purchaser expenses. The average prices received for crude oil and natural gas sales are positively impacted by settlement payments received under our derivative agreements as discussed below under "Loss on Hedging Contracts / Settlement Payments."

During March 2006, there were grass fires in the Texas Panhandle area. These fires temporarily shut-in production on the Panhandle Properties until flow lines were restored. We estimate the temporary shut-in resulted in approximately $0.3 million reduction in revenues for March and April 2006. By mid-April 2006, the Panhandle Properties were producing at 95% of normal operations.

We expect future increases to sales through capital expenditures as previously discussed under "Capital Development Update."

Operating Expenses

2007 Fiscal Year v. 2006 Fiscal Year

For the 2007 Fiscal Year, our total operating expenses were $30.6 million, or $13.6 million higher than the 2006 Fiscal Year of $17.0 million. The $13.6 million increase is primarily attributed to:

•: Including a full twelve months of Panhandle and Pantwist Properties operating expenses, accounted for $6.9 million of the increase. The 2006 Fiscal Year included seven months of Panhandle Properties' revenue and two months of Pantwist Properties' revenue.
•: Higher general and administrative expenses of $5.2 million.
•: Higher operating expenses due to increased sales, as discussed under "Operating Revenues".

2006 Fiscal Year v. 2005 Fiscal Year

For the 2006 Fiscal Year, our total operating expenses were $17.0 million, or $9.5 million higher than the 2005 Fiscal Year of $7.5 million. The $9.5 million increase is primarily attributed to:

•: Including seven months of the Panhandle Properties operating expenses totaling $4.4 million;
•: Including two months of the Pantwist Properties operating expenses totaling $0.6 million;
•: Including two additional months of the Nowata Field operating expenses totaling $0.4 million;
•: Higher general & administrative expenses of $2.8 million; and
•: Higher other operating expenses due to increased sales, as discussed under "Operating Revenues".

Lease Operating Expenses

Our lease operating expenses ("LOE") consists of the costs of producing crude oil and natural gas such as labor, supplies, repairs, maintenance, and utilities. Our LOE per BOE showed a positive downward trend during the past three years as for the 2007, 2006 and 2005 Fiscal Years, the LOE per BOE was $21.78, $22.41 and $26.56, respectively, for our continuing operations. We generally incur a high amount of LOE because our fields are more mature and typically produce less oil and more

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

General and Administrative Expenses

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

2007 Fiscal Year v. 2006 Fiscal Year

For the 2007 Fiscal Year, our G&A expenses totaled $12.8 million, which is $5.2 million higher than the Fiscal Year of $7.6 million. The primary contributors to the $5.2 million increase were:

•: Increased labor and staffing costs of $1.4 million;
•: Higher legal fees of $1.6 million to comply with regulatory requirements and for litigation;
•: Increased fees of $0.8 million for accounting services for SEC reporting and to achieve full compliance with the Section 404 of the Sarbanes-Oxley Act;
•: Expenses of $0.4 million to maintain the WO Energy offices; and
•: Other items totaling $1.0 million due to higher office rent expenses, increased board of director compensation and increased insurance costs.

For the 2007 Fiscal Year and 2006 Fiscal Year, our payroll and payroll-related costs comprise $4.0 million and $3.0 million, respectively, of our total G&A expenses. We expect these costs to continue to increase because the recent growth in the petroleum industry has increased competition for labor resources.

2006 Fiscal Year v. 2005 Fiscal Year

For the 2006 Fiscal Year, our G&A expenses totaled $7.6 million, which is $2.8 million higher than the 2005 Fiscal Year of $4.8 million. The primary contributors to the $2.8 million increase were:

•: Increased labor and staffing costs of $1.8 million;
•: Higher legal fees of $1.1 million to comply with regulatory requirements and for litigation;
•: Expenses associated with the Sabine joint venture of $0.4 million, as discussed in Note 7 of our consolidated financial statements for the year ended June 30, 2007;
•: Expenses of $0.3 million to maintain the WO Energy offices; and
•: Other items totaling $0.4 million are attributed to higher travel costs, board of director compensation, higher accounting fees and increased insurance costs.

Offsetting these increases was lower deferred compensation expense of $1.2 million.

Realized Gain/Unrealized Loss on Hedging Contracts

As discussed in Note 5 of our consolidated financial statements for the 2007 Fiscal Year and 2006 Fiscal Year, we paid $1.6 million and $6.1 million, respectively, to enter into financial contracts to set price floors for crude oil and natural gas through June 2010. We recorded an unrealized loss on

commodity derivatives of $1.8 million and $3.2 million, respectively, to reflect the fair value of the derivative instruments as of June 30, 2007 and 2006. By their nature, these derivative instruments can be highly volatile to our earnings. A five percent change in these prices for our derivative instruments can impact earnings by approximately $135,000. We did not have hedging contracts during the 2005 Fiscal Year.

Also, during the 2007 and 2006 Fiscal Years, as discussed in Note 5 of our consolidated financial statements, there were settlements under our commodity derivatives due to us amounting to $962,559 and $540,871, respectively, which are recorded as realized gain on commodity derivative. The settlements were cumulative monthly payments to us since the NYMEX natural gas price was lower than the "floor natural gas prices" ranging between $7.60 and $8.50 and the WTI-NYMEX oil price was lower than the "floor oil prices" ranging from $55 to $60. The cash flows relating to the derivative instruments are reflected in operating activities on our consolidated statements of cash flows.

As discussed in Note 4 of our consolidated financial statements, the Credit Agreement requires that we hedge no less than 50% and no more than 80% of the production volumes attributable to our proved producing reserves. We are required to maintain three year hedges, and to update our hedges semi-annually. We intend to enter into financial contracts to set price floors for our crude oil and natural gas production.

Interest Expense

For 2007 Fiscal Year and 2006 Fiscal Year, we incurred interest expense of $2.6 million and $2.4 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 4 of our consolidated financial statements. We did not have credit agreements during the 2005 Fiscal Year.

As discussed under "Liquidity and Capital Resources" and Note 4 of our consolidated financial statements, on September 6, 2006, we completed a private placement of preferred stock, common stock and warrants totaling gross proceeds of $80.9 million. The preferred dividend rate is 7.875%. These proceeds have been used to repay long-term debt of $68.75 million, and the remainder was used to provide working capital and for general corporate purposes, including the funding of a portion of our fiscal 2007 capital budget. Our outstanding subordinated debt totaling $15 million, with an interest rate of 12.74%, has been permanently retired. The Credit Agreement is our only source of long-term debt.

Deferred Income Tax Benefit

As the result of the recognition of the deferred tax liabilities assumed in the acquisitions of WO Energy and Square One, we have recorded a net deferred tax liability. This allows us to recognize deferred tax benefits from generation of net operating losses because a valuation allowance against such items is not required. We review our deferred tax assets at least quarterly and record a valuation allowance against those assets when we conclude that it is more likely than not that those assets will expire without being utilized. For the 2007, 2006 and 2005 Fiscal Year, we recorded a deferred income tax benefit of $1.9 million, $3.8 million and $0, respectively. For 2006, the $3.8 million benefit amounts to an effective tax rate of approximately 65%, due to recording the effect of a change in enacted rates in the State of Texas in May 2006, amounting to $1,840,000. See Note 11 of our consolidated financial statements for more information.

Income from Discontinued Operations

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 $6.9 million cash. The sale of the Rich Valley Properties resulted in a pre-tax gain of

$3.8 million. For 2007 Fiscal Year, we recognized income from the discontinued operations of $2.6 million. This is discussed in greater detail at Note 6 of the consolidated financial statements.

Preferred Stock Dividend

The preferred stock dividend during the 2007 Fiscal Year of $3.2 million resulted from the preferred stock financing, which was completed on September 6, 2006, as discussed in Note 2 of the consolidated financial statements. We did not have preferred stock dividends during the 2006 Fiscal Year or 2005 Fiscal Year.

Preferred Stock Discount

The reduced preferred stock discount amounting to $0.4 million occurred during the 2005 Fiscal Year and was attributable to certain issuances of preferred stock during that period. Since we did not issue preferred stock during the 2006 Fiscal Year and did not issue preferred stock at a discount during the 2007 Fiscal Year, there is no preferred stock discount for the 2007 or 2006 Fiscal Years.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at June 30, 2007 for the periods shown:

Amounts in $000s	Total		Less than One Year		One To Three Years		Three to Five Years		More Than Five Years
Long-term debt(1)	$	33,500	$	—	$	33,500	$	—	$	—
Operating lease obligations (See Note 12)	$	1,635	$	436	$	865	$	334	$	—
Total contractual obligations	$	35,135	$	436	$	34,365	$	334	$	—

(1): The credit facility matures on November 29, 2009. At September 6, 2007, there was $41.5 million outstanding under the credit facility.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

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.

	30-Sep			31-Dec			31-Mar			30-Jun
Fiscal Year Ended June 30, 2007
Operating revenues from continuing operations	$	7,674,800		$	6,157,932		$	5,883,454		$	8,636,840
Operating income (loss) from continuing operations		133,478			(424,659	)		(1,587,287	)		(320,439	)
Loss from continuing operations		(442,914	)		(530,281	)		(2,250,689	)		(210,507	)
Income from discontinued operations, net of tax		75,021			85,103			59,559			2,424,851
Net income (loss) applicable to common stock		(636,492	)		(1,412,149	)		(3,158,102	)		1,247,372
Net income (loss) per share—basic and diluted		(0.02	)		(0.04	)		(0.10	)		0.04
Fiscal Year Ended June 30, 2006
Operating revenues from continuing operations	$	1,541,874		$	2,625,499		$	4,835,493		$	6,857,696
Operating income (loss) from continuing operations		(696,335	)		(691,401	)		39,201			254,119
Net income (loss) from continuing operations		(610,373	)		(1,656,251	)		(1,207,722	)		1,144,442
Income from discontinued operations, net of tax		152,416			169,715			76,694			86,655
Net income (loss) applicable to common stock		(457,957	)		(1,486,536	)		(1,131,028	)		1,231,097
Net income (loss) per share—basic and diluted		(0.02	)		(0.06	)		(0.05	)		0.05

Significant 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 requires management to make judgments and estimates, including choices between acceptable GAAP alternatives.

Oil and Natural Gas Properties and Equipment

Depreciation and depletion of producing properties is computed on the units-of-production method based on estimated proved oil and natural gas reserves. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.

At least quarterly, or more frequently if conditions indicate that long-term assets may be impaired, the carrying value of property 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. We had no significant unproved properties at June 30, 2007 or 2006. No impairment was necessary at June 30, 2007, 2006 or 2005.

Estimates of Proved Reserves

The term proved reserves is defined by the Securities and Exchange Commission 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 oil, gas and 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, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating 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 oil and natural gas actually produced.

Asset Retirement Obligation

Our financial statements reflect the fair value for any asset retirement obligation that can be reasonably estimated upon acquiring or drilling a well, and the 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.

Revenue Recognition

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 collects or receives the quantities. 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; therefore, we do not incur transportation costs related to our sales of oil and natural gas production.

As of June 30, 2007 and 2006, we sold our crude oil and natural gas production to several independent purchasers. During the year ended June 30, 2007, we had sales of 10% or more of our total revenues to primarily four customers which represented 36%, 18%, 17% and 16% of total operating revenue, respectively. During the year ended June 30, 2006, we had sales of 10% or more of our total revenues to five customers representing 29%, 25%, 12%, 12% and 10% of total operating revenue, respectively. During the year ended June 30, 2005, we had sales to primarily three customers which represented 58%, 21% and 19% of total operating revenue, respectively.

Stock Compensation Expense

Effective July 1, 2006, we accounted for share-based payments for services provided by employee to employer in accordance with SFAS No. 123(R), which generally requires companies to value the fair value of employee stock options and other equity-based compensation at the grant date and record the expense over the vesting period. We adopted SFAS No. 123(R) beginning July 1, 2006. Since we had expensed stock options in accordance with SFAS No. 123, the adoption of SFAS No. 123(R) did not materially impact our operating results, financial position, or our cash flows.

Commodity Derivatives

We are required to hedge a portion of our production at specified prices for oil and natural gas under the Credit Agreement, as discussed in Note 4 to the consolidated financial statements. The objective is to reduce our exposure to commodity price risk associated with expected oil and natural gas production. By achieving this objective we intend to protect the outstanding debt amounts and maximize the funds available under our existing Credit Agreement, which helps us to support our annual capital budgeting and expenditure plans. We have entered into commodity derivatives that set "price floors" for our crude oil and natural gas production that are recorded as derivative assets on our consolidated balance sheets and are measured at fair value.

At June 30, 2007, we had no commodity derivatives that set a price ceiling. We do not hold or issue commodity derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our commodity derivatives. We anticipate, however, that our counterparty, Union Bank of California, will be able to fully satisfy their obligations under the commodity derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts subject to credit risk but we monitor the credit standing of the counterparty.

We have elected not to designate the commodity derivatives to which we are a party as hedges, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur.

Changes in the fair values of our derivative instruments are recorded immediately in earnings as unrealized gain or loss on commodity derivatives on our consolidated statements of operations. Cash flows resulting from the settlement of our derivative instruments are recorded as realized gains on commodity derivatives on the consolidated statements of operations.

New Accounting Pronouncements

SFAS No. 157, Fair Value Measurements ("SFAS No. 157"), was issued by the Financial Accounting Standards Board ("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 that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of SFAS No. 157 will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect adoption of SFAS No. 157 will have a material impact on our financial position, results of operations or cash flows.

On July 13, 2006, the FASB released FIN 48, "Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109" ("FIN 48"). FIN 48 requires companies to evaluate and disclose material uncertain tax positions it has taken with various taxing jurisdictions. We have reviewed FIN 48 and determined the adoption of FIN 48 will not materially affect our operating results, financial position, or future cash flows. We adopted FIN 48 on July 1, 2007.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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 Credit Agreement, we are required to enter into financial contracts to hedge approximately 50% to 80% of our production at specified floors for oil and natural gas between $55 and $60 per barrel and between $7.50 and $8.50 per Mcf. Therefore, for the hedged production, we will receive at least the floor prices. During the year ended June 30, 2007, approximately 74% of our production was hedged. The remaining 26% was not subject to the floors and is subject to the volatility and price fluctuations of oil and natural gas.

Assuming that the prices that we receive for our crude oil and natural gas production are above the above described floors, based on our actual fiscal year sales volumes for the year ended June 30, 2007, a 10% decline in the prices we receive for our crude oil and natural gas production would have had an approximate $3 million impact on our revenues.

Interest Rate Risk

At June 30, 2007, we had borrowings of $33.5 million outstanding under our Credit Agreement. At June 30, 2007, if there had been an increase in the interest rate of 1%, our interest expense would have increased by $335,000 annually.

Commodity Derivatives

We are required to hedge a portion of our production at specified prices for oil and natural gas under the Credit Agreement, as discussed in Note 4 of the consolidated financial statements. The objective is to reduce our exposure to commodity price risk associated with expected oil and natural gas production. By achieving this objective we intend to protect the outstanding debt amounts and maximize the funds available under our existing Credit Agreement, which helps us to support our annual capital budgeting and expenditure plans. We have entered into commodity derivatives that set "price floors" for our crude oil and natural gas production.

During our years ended June 30, 2007 and 2006, we paid $1.6 million and $6.1 million to enter into commodity derivatives to set price floors. These financial contracts are summarized in the table below.

Time Period	Floor Oil Price		Barrels per Day	Floor Gas Price		Gas Mcf per Day	Barrels of Equivalent Oil per Day
1/1/06 - 12/31/06	$	60	534	$	8.50	1,784	832
6/1/06 - 12/31/06	$	60	79	$	7.60	690	194
1/1/07 - 12/31/07	$	55	507	$	8.00	1,644	781
1/1/07 - 12/31/07	$	60	72	$	7.60	658	182
1/1/08 - 12/31/08	$	55	479	$	7.50	1,534	735
1/1/08 - 12/31/08	$	60	66	$	7.60	592	164
1/1/09 - 4/30/09	$	60	59	$	7.60	559	152
1/1/09 - 12/31/09	$	55	395	$	7.60	1,644	668
1/1/10 - 6/30/10	$	55	365	$	7.00	1,657	641

During the years ended June 30, 2007 and 2006, there were settlements under our commodity derivatives due to us amounting to $962,559 and $540,871, respectively, which are recorded as realized

gain on commodity derivatives on our consolidated statements of operations. The settlements were cumulative monthly payments due to us since the NYMEX natural gas price was lower than the "floor natural gas prices" ranging between $7.60 and $8.50 and the WTI-NYMEX oil price was lower than the "floor oil prices" ranging from $55 to $60. The cash flows relating to the derivative instruments are reflected in operating activities on our consolidated statements of cash flows.

We obtained mark-to-market valuations used for our commodity derivatives from an external source and validated such valuations using quotes for exchange-traded options with similar terms. In accordance with SFAS No. 133, we recorded the $7.7 million in payments as derivative assets. SFAS No. 133 also provides that commodity derivatives be measured at fair value on the balance sheet date. During the years ended June 30, 2007 and 2006, we recognized unrealized loss on commodity hedges on our consolidated statements of operations amounting to $1,810,000 and $3,245,588, respectively, under unrealized loss on hedge contracts. At June 30, 2007, our derivative assets totaled $2,691,974, of which $1,881,800 was considered long-term.

If crude oil prices fell $1 below our hedged crude oil price floor, we would save approximately $220,000 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 save approximately $870,000 due to having the natural gas price floor hedge in place.

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 the 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 provide reasonable assurance that the information required to be disclosed by us in reports filed 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 Securities and Exchange Commission.

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, 2007 were effective.

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 Securities Exchange Act of 1934 Rule 13a-15(f) and 15d-15(f). 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 U.S. generally accepted accounting principles. 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 transactions 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 generally accepted accounting principles, 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, 2007, 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, 2007 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting 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 audit report on management's assessment of the effectiveness of the Company's internal control over financial reporting as of June 30, 2007. The report, dated September 6, 2007, which expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an opinion that the Company had maintained effective internal control over financial reporting as of June 30, 2007 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is included below.

Report of Independent Registered Public Accounting Firm

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

We have audited management's assessment, included in the accompanying "Management's Annual Report on Internal Control Over Financial Reporting," that Cano Petroleum, Inc. maintained effective internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission (COSO). 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. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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, management's assessment that Cano Petroleum, Inc. maintained effective internal control over financial reporting as of June 30, 2007, is fairly stated, 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). Also in our opinion, Cano Petroleum, Inc. maintained, in all material respects, effective internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Cano Petroleum, Inc. and our report dated September 7, 2007 expressed an unqualified opinion.

/s/ Hein & Associates LLP

HEIN & ASSOCIATES LLP
Dallas, Texas
September 7, 2007

Changes in Internal Controls

During the quarter ended June 30, 2007, there was no change in our internal control over financial reporting that has materially effected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

On September 7, 2007, our director Donnie D. Dent announced that he will not seek re-election as a director at the 2007 Annual Meeting of Stockholders.

PART III

Item 10. Directors, Executive Officers of the Registrant and Corporate Governance

Information required by this item relating to our (i) directors, nominees for 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 Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 29, 2007, and that is 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 Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 29, 2007, and that is 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 Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 29, 2007, and that is 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 Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 29, 2007, and that is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information relating to (i) fees billed to the Company by the independent public accountants for services for the years ended June 30, 2007 and 2006 and (ii) 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 Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 29, 2007, and that is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a): The following documents are filed as part of this report:
1.: Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of June 30, 2007 and 2006, Consolidated Statements of Operations for each of the three years in the period ended June 30, 2007, Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended June 30, 2007, Consolidated Statements of Cash Flows for each of the three years in the period ended June 30, 2007, 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.

Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

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 11, 2007	By:	/s/ S. JEFFREY JOHNSON S. Jeffrey Johnson Chief Executive Officer
Date: September 11, 2007	By:	/s/ MORRIS B. SMITH Morris B. Smith Senior Vice-President and Chief Financial Officer
Date: September 11, 2007	By:	/s/ MICHAEL J. RICKETTS Michael J. Ricketts Vice-President and Principal Accounting Officer

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned directors of Cano Petroleum, Inc. hereby constitutes and appoints S. Jeffrey Johnson and Morris B. Smith 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 Securities and Exchange Commission, 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 11, 2007
/s/ DONNIE D. DENT Donnie D. Dent	Director	September 11, 2007
/s/ GERALD W. HADDOCK Gerald W. Haddock	Director	September 11, 2007

/s/ RANDALL BOYD Randall Boyd	Director	September 11, 2007
/s/ ROBERT L. GAUDIN Robert L. Gaudin	Director	September 11, 2007
/s/ DONALD W. NIEMIEC Donald W. Niemiec	Director	September 11, 2007
/s/ WILLIAM O. POWELL III William O. Powell III	Director	September 11, 2007

INDEX TO EXHIBITS

Exhibit Number		Description
2.1		Agreement and Plan of Merger made as of the 26^th day of May 2004, by and 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 by reference from Exhibit 99.1 to Current Report on Form 8-K, filed on June 8, 2004.
2.2+		Management Stock Pool Agreement dated May 28, 2004, incorporated by reference from Exhibit 2.2 to Current Report on Form 8-K/A, filed on August 11, 2004.
2.3+		Investment Escrow Agreement dated May 28, 2004, incorporated by reference from Exhibit 2.3 to Current Report on Form 8-K/A, filed on August 11, 2004.
2.4		Stock Purchase Agreement dated June 30, 2004, by and between Cano Petroleum, Inc., as Buyer, and Jerry D. Downey and Karen S. Downey, as Sellers, incorporated by reference from Exhibit 99.1 to Current Report on Form 8-K, filed on July 15, 2004.
2.5		Purchase and Sale Agreement, dated August 16, 2004, by and between Cano Energy Corporation and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K, filed on August 25, 2004.
2.6		Purchase and Sale Agreement, dated September 2, 2004, by and between Nowata Oil Properties LLC and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K, filed on September 20, 2004.
2.7		Purchase and Sale Agreement dated February 6, 2005 by and between Square One Energy, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on March 7, 2005.
2.8		Stock Purchase Agreement by and among Cano Petroleum, Inc., W. O. Energy of Nevada, Inc., Miles O'Loughlin and Scott White dated November 29, 2005 (the schedule and exhibits have been omitted from this filing. An exhibit to the schedules and exhibits is contained in the Stock Purchase Agreement and the schedule and exhibits are available to the Securities and Exchange Commission upon request), incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on December 5, 2005.
2.9		Asset Purchase and Sale Agreement 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 dated as of April 25, 2006 (The schedules and exhibits have been omitted from this filling. An exhibit to the schedules and exhibits is contained in the Asset Purchase and Sale Agreement and the schedules and exhibits are available to the Securities and Exchange Commission upon request), incorporated by reference from Exhibit 2.1 to Quarterly Report on Form 10-QSB filed on May 15, 2006.
2.10		Amendment No. One to Stock Purchase Agreement by and among Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., Estate of Miles O'Loughlin and Scott White dated May 13, 2006 incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on May 15, 2006.

2.11		Purchase and Sale Agreement by and among UHC New Mexico Corporation, as Seller, Cano Petro of New Mexico, Inc., as Buyer, and Cano Petroleum, Inc., for Certain Limited Purposes, dated March 30, 2007, incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on April 4, 2007. (The schedules and exhibits have been omitted from this filing. An exhibit to the schedules and exhibits is contained in the Purchase and Sale Agreement and the schedules and exhibits are available to the Securities and Exchange Commission upon request).
2.12		Agreement for Purchase and Sale among Ladder Companies, Inc. and Tri-Flow, Inc., as Seller, and Anadarko Minerals, Inc., as Buyer, dated June 11, 2007, incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on June 12, 2007. (The schedules and exhibits have been omitted from this filing. An exhibit to the schedules and exhibits is contained in the Agreement for Purchase and Sale and the schedules and exhibits are available to the Securities and Exchange Commission upon request).
3.1		Certificate of Incorporation, incorporated by reference from Exhibit 3.1 to the Company's registration statement on Form 10-SB (File No. 000-50386), filed on September 4, 2003.
3.2		Certificate of Ownership, amending the Company's Certificate of Incorporation, incorporated by reference from Exhibit 3.2 to the Company's Annual Report on Form 10-KSB filed on September 23, 2004.
3.3		Bylaws, incorporated by reference from Exhibit 3.2 to the Company's registration statement on Form 10-SB (File No. 000-50386), filed on September 4, 2003.
3.4		Designation for Series A Convertible Preferred Stock, included in the Company's Certificate of Incorporation, incorporated by reference from Exhibit 3.1 to the Company's registration statement on Form 10-SB (File No. 000-50386), filed on September 4, 2003.
3.5		Certificate of Designation for Series B Convertible Preferred Stock, incorporated by reference from Exhibit 99.2 to Current Report Form 8-K, filed on June 8, 2004.
3.6		Certificate of Designation for Series C Convertible Preferred Stock, incorporated by reference from Exhibit 99.2 to Current Report Form 8-K, filed with the Securities and Exchange Commission on July 15, 2004.
3.7		Certificate of Designation for Series D Convertible Preferred Stock incorporated by reference from Exhibit 3.1 to Current Report on Form 8-K, filed on September 7, 2006.
3.8		Certificate of Amendment to Certificate of Incorporation, incorporated by reference from Exhibit 3.1 to Current Report on Form 8-K, filed on January 23, 2007.
4.1		Registration Rights Agreement by and between Cano Petroleum, Inc. and Miles O'Loughlin dated November 29, 2005, incorporated by reference from Exhibit 4.1 to Current Report on Form 8-K filed on December 5, 2005.
4.2		Registration Rights Agreement by and between Cano Petroleum, Inc. and Scott White dated November 29, 2005, incorporated by reference from Exhibit 4.2 to Current Report on Form 8-K filed on December 5, 2005.
4.3		Amendment No. One to the Registration Rights Agreement by and between Cano Petroleum, Inc. and Estate of Miles O'Loughlin dated May 13, 2006 and effective as of November 29, 2005 incorporated by reference from Exhibit 4.1 to Current Report on Form 8-K filed on May 15, 2006.

4.4		Amendment No. One to the Registration Rights Agreement by and between Cano Petroleum, Inc. and Scott White dated May 13, 2006 and effective as of November 29, 2005 incorporated by reference from Exhibit 4.2 to Current Report on Form 8-K filed on May 15, 2006.
4.5		Registration Rights Agreement dated August 25, 2006 by and among Cano Petroleum, Inc. and the Buyers listed therein, incorporated by reference from Exhibit 4.1 to Amendment to Current Report on Form 8-K/A filed on August 31, 2006.
10.1+		Stock Option Agreement dated December 16, 2004 between Cano Petroleum, Inc. and Gerald W. Haddock, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on December 16, 2004.
10.2+		2005 Directors' Stock Option Plan, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on Jun 28, 2005.
10.3		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Howard Hughes Medical Institute, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on September 22, 2005.
10.4		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and The Robert Wood Johnson Foundation, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on September 22, 2005.
10.5		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Laborers' District Council and Contractors' of Ohio Pension Fund, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on September 22, 2005.
10.6		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Ohio Carpenters' Pension Fund, incorporated by reference from Exhibit 10.4 to Current Report on Form 8-K filed on September 22, 2005.
10.7		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and New York Nurses Association Pension Plan, incorporated by reference from Exhibit 10.5 to Current Report on Form 8-K filed on September 22, 2005.
10.8		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Public Sector Pension Investment Board, incorporated by reference from Exhibit 10.6 to Current Report Form 8-K filed on September 22, 2005.
10.9		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Spindrift Investors (Bermuda) L.P., incorporated by reference from Exhibit 10.7 to Current Report on Form 8-K filed on September 22, 2005.
10.10		Subscription Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and Spindrift Partners, L.P., incorporated by reference from Exhibit 10.8 to Current Report on Form 8-K filed on September 22, 2005.
10.11+		Stock Option Agreement dated September 16, 2005 by and between Cano Petroleum, Inc. and James K. Teringo, Jr., incorporated by reference from Exhibit 10.10 to Current Report on Form 8-K filed on September 22, 2005.
10.12		Subscription Agreement dated September 14, 2005 by and between Cano Petroleum, Inc. and Touradji Global Resources Master Fund, Ltd., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K on September 20, 2005.

10.13		Subscription Agreement dated September 14, 2005 by and between Cano Petroleum, Inc. and Renaissance US Growth Investment Trust PLC, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on September 20, 2005.
10.14		Subscription Agreement dated September 14, 2005 by and between Cano Petroleum, Inc. and BFS US Special Opportunities Trust PLC, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on September 20, 2005.
10.15		Subscription Agreement dated September 14, 2005 by and between Cano Petroleum, Inc. and Crestview Capital Master, LLC, incorporated by reference from Exhibit 10.4 to Current Report on Form 8-K filed on September 20, 2005.
10.16		Omnibus Agreement among Cano Petroleum, Inc., Haddock Enterprises, LLC, Carlile Management, LLC and Sabine Partners, LP dated November 4, 2005, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on November 9, 2005.
10.17		Amended and Restated Regulations of Sabine Production Operating, LLC among Cano Petroleum, Inc., Haddock Enterprises, LLC and Carlile Management, LLC dated November 4, 2005, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on November 9, 2005.
10.18		Compensation Reimbursement Agreement between Cano Petroleum, Inc. and Sabine Production Operating, LLC dated November 4, 2005, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on November 9, 2005.
10.19		First Amendment to Amended and Restated Regulations of Sabine Production Operating, LLC effective July 8, 2007, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on February 1, 2007.
10.20		Credit Agreement among Cano Petroleum, Inc., as Borrower, The Lenders Party Hereto From Time to Time, as Lenders, and Union Bank of California, N.A., as Administrative Agent and as issuing Lender, dated November 29, 2005, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on December 5, 2005.
10.21		Subordinated Credit Agreement among Cano Petroleum, Inc., as Borrower, The Lenders Party Hereto From Time to Time, as Lenders, and Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent, dated November 29, 2005, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on December 5, 2005.
10.22		Guaranty Agreement by and 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, dated November 29, 2005, incorporated by reference from Exhibit 10.3 to the Current Report on Form 8-K filed on December 5, 2005.
10.23		Guaranty Agreement by and 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 Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent, dated November 29, 2005, incorporated by reference from Exhibit 10.4 to the Current Report on Form 8-K filed on December 5, 2005.

10.24		Escrow Agreement by and among Cano Petroleum, Inc., Miles O'Loughlin, Scott White and The Bank of New York Trust Company, N.A., as Escrow Agent, dated November 29, 2005, incorporated by reference from Exhibit 10.5 to the Current Report on Form 8-K filed on December 5, 2005.
10.25		Amended and Restated Escrow Agreement dated as of June 18, 2007 by and among Cano Petroleum, Inc., the Estate of Miles O'Loughlin and Scott White, and The Bank of New York Trust Company, N.A., incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on June 21, 2007.
10.26		Pledge Agreement by and among Cano Petroleum, Inc., W. O. Energy of Nevada, Inc. and W O Energy, Inc. in favor of Union Bank of California, N.A., as Administrative Agent, dated November 29, 2005, incorporated by reference from Exhibit 10.6 to the Current Report on Form 8-K dated on December 5, 2005.
10.27		Security Agreement by and among Cano Petroleum, Inc., 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. Petroleum, Ltd., in favor of Union Bank of California N.A. as Administrative Agent, dated November 29, 2005, incorporated by reference from Exhibit 10.7 to the Current Report on Form 8-K filed on December 5, 2005.
10.28+		Cano Petroleum, Inc. 2005 Long-Term Incentive Plan dated December 7, 2005, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on December 9, 2005.
10.29+		Form of Stock Option Agreement (December 2005), incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on December 19, 2005.
10.30		Summary of Terms of Purchase of Overriding Royalty Interests by Cano Petroleum, Inc. from Theprivate Energy Company, Inc. dated December 27, 2005, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on January 3, 2006.
10.31+		Summary Sheet: Director Compensation, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on January 12, 2006.
10.32+		Employment Agreement between Cano Petroleum, Inc. and S. Jeffrey Johnson dated effective January 1, 2006, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on January 19, 2006.
10.33+		Amendment to Employment Agreement of Thomas Cochrane effective January 1, 2006, incorporated by reference from Exhibit 10.3 to the Current Report on Form 8-K filed on January 19, 2006.
10.34+		Amendment to Employment Agreement of James K. Teringo, Jr. effective January 1, 2006, incorporated by reference from Exhibit 10.4 to the Current Report on Form 8-K filed on January 19, 2006.
10.35		Gas Purchase Contract between W. O. Operating Company, Ltd. and Duke Field Services L.P. dated November 1, 2003, incorporated by reference from Exhibit 10.17 to the Quarterly Report on Form 10-QSB filed on February 14, 2006.
10.36		Gas Purchase Contract by and between W. O. Operating Company Limited, as Seller, and One OK Texas Field Services LP, as Buyer, dated January 1, 2005, incorporated by reference from Exhibit 10.18 to the Quarterly Report on Form 10-QSB filed on February 14, 2006.

10.37		Amendment No. 1 dated February 24, 2006 to the $100,000,000 Credit Agreement among Cano Petroleum, Inc., as Borrower, The Lenders Party Hereto From Time to Time as Lenders and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender dated November 29, 2005 incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on March 1, 2006.
10.38		Amendment No. 2, Assignment and Agreement dated as of 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, the Lenders and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender, incorporated by reference from Exhibit 10.7 to Quarterly Report on Form 10-QSB filed on May 15, 2006.
10.39		First Amendment to Subordinated Credit Agreement dated as of April 28, 2006 by and among Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent and Lender, UnionBanCal Equities, Inc., 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., and Pantwist, LLC, incorporated by reference from Exhibit 10.8 to Quarterly Report Form 10-QSB filed May 15, 2006.
10.40		Supplement No. 1 dated as of April 28, 2006 to the Guaranty Agreement dated as of November 29, 2005, by Pantwist, LLC in favor of Union Bank of California, as Administrative Agent, incorporated by reference from Exhibit 10.9 to Quarterly Report on Form 10-QSB filed May 15, 2006.
10.41		Supplement No. 1 dated as of April 28, 2006 to the Guaranty Agreement dated as of November 29, 2005, by Pantwist, LLC in favor of Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as Administrative Agent, incorporated by reference from Exhibit 10.10 to Quarterly Report on Form 10-QSB filed on May 15, 2006.
10.42		Supplement No. 1 dated as of April 28, 2006 to the Pledge Agreement dated as of 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 by reference from Exhibit 10.11 to Quarterly Report Form 10-QSB filed on May 15, 2006.
10.43		Supplement No. 1 dated as of April 28, 2006 to the Security Agreement dated as of November 29, 2005, by Pantwist, LLC in favor of Union Bank of California, N.A., as Collateral Trustee, incorporated by reference from Exhibit 10.12 to Quarterly Report on Form 10-QSB filed on May 15, 2006.
10.44		Waiver from Union Bank of California, N.A. dated February 14, 2006 related to Credit Agreement dated as of November 29, 2005, incorporated by reference from Exhibit 10.13 to Quarterly Report on Form 10-QSB filed on May 15, 2006.
10.45		Waiver from Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio dated February 14, 2006 related to Subordinated Credit Agreement dated as of November 29, 2005, incorporated by reference from Exhibit 10.14 to Quarterly Report on Form 10-QSB filed on May 15, 2006.

10.46		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 by reference from Exhibit 10.1 to Current Report on Form 8-K filed on May 15, 2006.
10.47		Second Amendment to Subordinated 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., Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio and UnionBanCal Equities, Inc. dated May 12, 2006 and effective as of March 31, 2006, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on May 15, 2006.
10.48+		Employment Agreement of Morris B. Smith effective June 1, 2006, incorporated by reference from Exhibit 10.1 on Current Report on Form 8-K filed on June 6, 2006.
10.49+		Second Amendment to Employment Agreement of James K. Teringo, Jr. effective June 1, 2006, incorporated by reference from Exhibit 10.2 in Current Report on Form 8-K filed on June 6, 2006.
10.50+		Second Amendment to Employment Agreement of John Lacik effective June 1, 2006, incorporated by reference from Exhibit 10.3 on Current Report on Form 8-K filed on June 6, 2006.
10.51+		Second Amendment to Employment Agreement of Michael J. Ricketts effective June 1, 2006, incorporated by reference from Exhibit 10.4 on Current Report on Form 8-K filed on June 6, 2006.
10.52+		Employee Restricted Stock Award Agreement of Morris B. Smith effective June 1, 2006, incorporated by reference from Exhibit 10.5 on Current Report Form 8-K filed on June 6, 2006.
10.53+		Employee Restricted Stock Award Agreement of James K. Teringo, Jr. effective June 1, 2006, incorporated by reference from Exhibit 10.6 on Current Report on Form 8-K filed on June 6, 2006.
10.54+		Employee Restricted Stock Award Agreement of John Lacik effective June 1, 2006, incorporated by reference from Exhibit 10.9 on Current Report Form 8-K filed on June 6, 2006.
10.55+		Employment Agreement of John Lacik effective May 1, 2005, incorporated by reference from Exhibit 10.8 on Current Report on Form 8-K filed on June 6, 2006.
10.56+		First Amendment to Employment Agreement of John Lacik effective May 1, 2005, incorporated by reference from Exhibit 10.9 on Form 8-K filed on June 6, 2006.
10.57+		Employment Agreement of Patrick McKinney effective June 1, 2006, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on November 9, 2006.
10.58+		First Amendment to Employment Agreement of Patrick McKinney dated November 9, 2006, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on November 9, 2006.

10.59+		Restricted Stock Award Agreement of Patrick McKinney dated June 1, 2006 incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on November 9, 2006.
10.60		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 by reference from Exhibit 10.1 to Current Report on Form 8-K filed on June 7, 2006.
10.61		Third Amendment to Subordinated 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., Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio and UnionBanCal Equities, Inc. dated June 30, 2006, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on June 7, 2006.
10.62+		Employment Agreement of Michael J. Ricketts effective July 1, 2006, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on August 17, 2006.
10.63+		Employee Restricted Stock Award Agreement of Morris B Smith dated August 11, 2006, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on August 17, 2006.
10.64+		Stock Option Agreement of Patrick W. Tolbert dated August 11, 2006, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on August 17, 2006.
10.65+		Stock Option Agreement of Dennis McCuistion dated August 11, 2006, incorporated by reference from Exhibit 10.4 to Current Report on Form 8-K filed on August 17, 2006.
10.66		Securities Purchase Agreement dated August 25, 2006 by and among Cano Petroleum, Inc. and the Buyers listed therein, incorporated by reference from Exhibit 10.1 to Amendment to Current Report on Form 8-K/A filed on August 31, 2006.
10.67		Form of Warrant to Purchase Common Stock dated September 6, 2006 by Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on September 11, 2006.
10.68+		Amendment No. One dated December 28, 2006 to the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on January 4, 2007.
10.69+		Stock Option Agreement dated December 28, 2006 by and between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on January 4, 2007.
10.70+		Stock Option Agreement dated December 28, 2006 by and between Cano Petroleum, Inc. and Morris B. Smith, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on January 4, 2007.
10.71+		Stock Option Agreement dated December 28, 2006 by and between Cano Petroleum, Inc. and Patrick McKinney, incorporated by reference from Exhibit 10.4 to Current Report on Form 8-K filed on January 4, 2007.

10.72+		Stock Option Agreement dated December 28, 2006 by and between Cano Petroleum, Inc. and James K. Teringo, Jr., incorporated by reference from Exhibit 10.5 to Current Report on Form 8-K filed on January 4, 2007.
10.73+		Stock Option Agreement dated December 28, 2006 by and between Cano Petroleum, Inc. and Michael J. Ricketts, incorporated by reference from Exhibit 10.6 to Current Report Form 8-K filed on January 4, 2007.
10.74+		Stock Option Agreement of Gerald Haddock dated December 28, 2006, incorporated by reference from Exhibit 10.75 to Registration Statement on Form S-1 (333-126167) filed on January 23, 2007.
10.75+		Stock Option Agreement of Don Dent dated December 28, 2006, incorporated by reference from Exhibit 10.76 to Registration Statement on Form S-1 (333-126167) filed on January 23, 2007.
10.76+		Stock Option Agreement of Randall Boyd dated December 28, 2006, incorporated by reference from Exhibit 10.77 to Registration Statement on Form S-1 (333126167) filed on January 23, 2007.
10.77+		Stock Option Agreement of James Underwood dated December 28, 2006, incorporated by reference from Exhibit 10.78 to Registration Statement on Form S-1 (333-126167) filed on January 23, 2007.
10.78+		Stock Option Agreement of Patrick Tolbert dated December 28, 2006, incorporated by reference from Exhibit 10.79 to Registration Statement on Form S-1 (333-126167) filed on January 23, 2007.
10.79+		Stock Option Agreement of Dennis McCuistion dated December 28, 2006, incorporated by reference from Exhibit 10.80 to Registration Statement on Form S-1 (333-126167) filed on January 23, 2007.
10.80		Amendment No. 5 and Agreement dated as of March 6, 2007 by and 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 by reference from Exhibit 10.1 to Current Report on Form 8-K filed on March 12, 2007.
10.81		Supplement No. 2 dated as of March 6, 2007 to the Security Agreement dated as of November 29, 2005, by Cano Petro of New Mexico, Inc. in favor of Union Bank of California, as Collateral Trustee, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on March 12, 2007.
10.82		Supplement No. 2 dated as of March 6, 2007 to the Guaranty Agreement dated as of November 29, 2005, by Cano Petro of New Mexico, Inc. in favor of Union Bank of California, as Administrative Agent, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on March 12, 2007.
10.84		Supplement No. 2 dated as of March 6, 2007 to the Pledge Agreement dated as of 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 by reference from Exhibit 10.4 to Current Report on Form 8-K filed on March 12, 2007.

10.85		Assignment and Agreement dated as of March 7, 2007 by and 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 by reference from Exhibit 10.5 to Current Report on Form 8-K filed on March 12, 2007.
10.86+		Stock Option Agreement of William O. Powell, dated April 4, 2007, incorporated by reference from Exhibit 10.7 to Quarterly Report on Form 10-Q filed on May 12, 2007.
10.87+		Stock Option Agreement of Robert L. Gaudin, dated April 4, 2007, incorporated by reference from Exhibit 10.8 to Quarterly Report on Form 10-Q filed on May 12, 2007.
10.88+		Stock Option Agreement of Donald W. Niemiec, dated April 4, 2007, incorporated by reference from Exhibit 10.9 to Quarterly Report on Form 10-Q filed on May 12, 2007.
10.89		Settlement Agreement and Release dated February 9, 2007 by and among Mid-Continent Casualty Company, Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and W.O. Energy, Inc., incorporated by reference from Exhibit 10.1 to Registration Statement on Form S-3 (SEC No. 333-138003) filed on April 9, 2007.
10.90+		Separation Agreement, General Release and Covenant Not to Sue dated May 22, 2007 by and between Cano Petroleum, Inc. and James K. Teringo, Jr., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on May 25, 2007.
10.91+		Form of Restricted Stock Award Agreement (July 2007), incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on July 2, 2007.
10.92+		Form of Nonqualified Stock Option Agreement (July 2007), incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on July 2, 2007.
10.93+		First Amendment to Employment Agreement of Morris B. Smith dated June 29, 2007, incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on July 3, 2007.
10.94+		Second Amendment to Employment Agreement of Patrick McKinney dated June 29, 2007, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on July 3, 2007.
10.95+		First Amendment to Employment Agreement of Michael J. Ricketts dated June 29, 2007, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on July 3, 2007.
10.96+*		Form of Amendment to Restricted Stock Award Agreements (August 2007).
10.97+*		Form of Restricted Stock Award Agreement (August 2007).
10.98*		Amendment No. 6 dated as of August 13, 2007 by and 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.

10.99*		First Amendment to the Security Agreement dated as of July 9, 2007, by and 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.
10.100*		First Amendment to the Pledge Agreement dated as of July 9, 2007, by and among Cano Petroleum, Inc., W.O. Operating Company, Ltd. and W.O. Production Company, Ltd. and Union Bank of California, N.A., as Senior Agent.
10.101+*		Audit Committee Chairman Compensation (June 2007).
10.102+*		Summary of Acceleration of Vesting and Extension of Exercise Period for Stock Options for Resigning Directors (June 2007).
10.103+*		Amendment dated June 29, 2007 to Stock Option Agreement of James Underwood dated December 15, 2005.
10.104+*		Amendment dated June 29, 2007 to Stock Option Agreement of James Underwood dated December 28, 2006.
10.105		Amendment No. 7 dated as of September 7, 2007 by and 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 by reference from Exhibit 10.1 to Current Report on Form 8-K filed on September 11, 2007.
21.1*		Subsidiaries of the Company.
23.1*		Consent of Hein & Associates LLP.
23.2*		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.

Item 8. Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Cano Petroleum—Years Ended June 30, 2007, 2006 and 2005
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets		F-2
Consolidated Statements of Operations		F-3
Consolidated Statements of Changes in Stockholders' Equity		F-4
Consolidated Statements of Cash Flows		F-5
Notes to Consolidated Financial Statements		F-6

Report of Independent Registered Public Accounting Firm

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

We have audited the consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries (collectively, the "Company") as of June 30, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2007, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 7, 2007 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ HEIN & ASSOCIATES LLP

HEIN & ASSOCIATES LLP
Dallas, Texas
September 7, 2007

F-1

CANO PETROLEUM, INC.

CONSOLIDATED BALANCE SHEETS

			June 30,
			2007			2006
*ASSETS*
Current assets
	Cash and cash equivalents		$	2,119,098		$	644,659
	Accounts receivable			4,081,498			3,563,649
	Derivative assets			810,174			1,176,959
	Prepaid expenses			309,216			205,349
	Inventory			292,405			396,081
	Other current assets			135			641,759

		Total current assets		7,612,526			6,628,456

Oil and gas properties and equipment, successful efforts method				189,842,882			138,066,641
Less accumulated depletion and depreciation				(6,201,635	)		(2,319,780	)

Net oil and gas properties				183,641,247			135,746,861

Fixed assets and other, net				1,547,875			2,081,763
Restricted cash (Note 12)				6,000,000			—
Derivative assets				1,881,800			1,705,855
Goodwill				785,796			785,796

TOTAL ASSETS			$	201,469,244		$	146,948,731

*LIABILITIES AND STOCKHOLDERS' EQUITY*
Current liabilities
	Accounts payable		$	7,508,795		$	2,304,198
	Oil and gas sales payable			1,345,537			1,399,047
	Accrued liabilities			1,421,484			321,183
	Taxes payable			450,062			419,692
	Current portion of asset retirement obligations			264,140			19,809

		Total current liabilities		10,990,018			4,463,929

Long-term liabilities
	Long-term debt			33,500,000			68,750,000
	Asset retirement obligations			2,150,930			1,587,569
	Deferred tax liability			32,371,000			31,511,000
	Deferred litigation credit (Note 12)			6,000,000			—

		Total liabilities		85,011,948			106,312,498

Temporary Equity
	Series D convertible preferred stock and paid-in-kind dividend; par value $.0001 per share, stated value $1,000 per share; 49,116 authorized and 49,116 shares issued in 2007; liquidation preference of $50,862,925 and zero, respectively.			47,596,061			—
Commitments and contingencies (Note 12)
Stockholders' equity
	Common stock, par value $.0001 per share; 100,000,000 authorized; 33,956,392 and 26,987,941 shares issued in 2007 and 2006, respectively; and 32,688,098 and 25,719,647 shares outstanding in 2007 and 2006.			3,268			2,572
	Additional paid-in capital			85,238,490			53,054,812
	Accumulated deficit			(15,809,791	)		(11,850,419	)
	Treasury stock, at cost; 1,268,294 shares			(570,732	)		(570,732	)

		Total stockholders' equity		68,861,235			40,636,233

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY			$	201,469,244		$	146,948,731

See accompanying notes to these consolidated financial statements.

F-2

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

			Years Ended June 30,
			2007			2006			2005
Operating Revenues:
	Crude oil and natural gas sales		$	28,353,026		$	15,860,562		$	3,764,015
Operating Expenses:
	Lease operating			10,885,393			6,240,986			2,068,881
	Production and ad valorem taxes			2,465,191			1,153,775			223,566
	General and administrative			12,755,524			7,622,508			4,753,609
	Depletion and depreciation			4,305,696			1,847,217			370,899
	Accretion of discount on asset retirement obligations			140,129			90,492			48,204

		Total operating expenses		30,551,933			16,954,978			7,465,159

Loss from operations				(2,198,907	)		(1,094,416	)		(3,701,144	)
Other income (expense):
Unrealized loss on commodity derivatives				(1,810,000	)		(3,245,588	)		—
Realized gain on commodity derivatives				962,559			540,871			—
Interest expense				(2,559,619	)		(2,426,321	)		—
Interest income				253,026			124,467			11,661

		Total other income (expense)		(3,154,034	)		(5,006,571	)		11,661

Loss from continuing operations before income taxes				(5,352,941	)		(6,100,987	)		(3,689,483	)
Deferred income tax benefit				1,918,551			3,771,083			—

Loss from continuing operations				(3,434,390	)		(2,329,904	)		(3,689,483	)
Income from discontinued operations, net of tax of $1,487,551 in 2007, $273,083 in 2006 and $0 in 2005				2,644,534			485,480			716,341

Net loss				(789,856	)		(1,844,424	)		(2,973,142	)
Preferred stock dividend				3,169,516			—			—
Preferred stock discount				—			—			416,534

Net loss applicable to common stock			$	(3,959,372	)	$	(1,844,424	)	$	(3,389,676	)

Net income (loss) per share—basic and diluted
	Continuing operations		$	(0.22	)	$	(0.10	)	$	(0.35	)
	Discontinued operations			0.09			0.02			0.06

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

Weighted average common shares outstanding
	Basic and diluted			30,758,441			22,364,099			11,839,080

See accompanying notes to these consolidated financial statements.

F-3

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

	Preferred Stock
	Series B					Series C					Common Stock														Treasury Stock
	Series B					Series C					Common Stock					Additional Paid-in Capital			Accumulated Deficit			Deferred Compensation			Treasury Stock
	Shares		Amount			Shares		Amount			Shares		Amount			Additional Paid-in Capital			Accumulated Deficit			Deferred Compensation			Shares	Amount			Total
Balance at July 1, 2004	2,000		$	1,865,894		1,400		$	1,265,894		15,647,204		$	1,565		$	8,643,137		$	(6,616,319	)	$	(2,227,406	)	—	$	—		$	2,932,765
Net proceeds from issuance of Series C Preferred Stock	—			(5,044	)	5,350			5,344,916		—			(113	)		(2,252	)		—			—		—		—			5,337,507
Preferred Series B & C shares converted to common shares during March 2005	(2,000	)		(1,860,850	)	(6,750	)		(6,610,810	)	2,466,665			247			8,471,413			—			—		—		—			—
Preferred stock dividend from beneficial conversion feature	—			—		—			—		—			—			416,534			(416,534	)		—		—		—			—
Net proceeds from issuance of common shares	—			—		—			—		1,350,000			135			4,750,648			—			—		—		—			4,750,783
Issuance of common shares for Square One Energy acquisition	—			—		—			—		888,888			89			3,519,907			—			—		—		—			3,519,996
Stock based compensation	—			—		—			—		—			—			144,255			—			—		—		—			144,255
Management shares returned to treasury stock	—			—		—			—		(15,783	)		—			—			—			7,102		15,783		(7,102	)		—
Amortization of deferred compensation	—			—		—			—		—			—			—			—			1,678,785		—		—			1,678,785
Net loss	—			—		—			—		—			—			—			(2,973,142	)		—		—		—			(2,973,142	)

Balance at June 30, 2005	—		$	—		—		$	—		20,336,974		$	1,923		$	25,943,642		$	(10,005,995	)	$	(541,519	)	15,783	$	(7,102	)	$	15,390,949
Net proceeds and assets from issuance of common shares	—			—		—			—		4,703,864			470			18,278,536			—			—		—		—			18,279,006
Issuance of common shares for WO Energy acquisition	—			—		—			—		1,791,320			179			8,240,000			—			—		—		—			8,240,179
Stock based compensation	—			—		—			—		140,000			—			592,634			—			(22,111	)	—		—			570,523
Escrow shares returned to Treasury	—			—		—			—		(1,252,511	)		—			—			—			563,630		1,252,511		(563,630	)		—
Net loss	—			—		—			—		—			—			—			(1,844,424	)		—		—		—			(1,844,424	)

Balance at June 30, 2006	—		$	—		—		$	—		25,719,647		$	2,572		$	53,054,812		$	(11,850,419	)	$	—		1,268,294	$	(570,732	)	$	40,636,233
Net proceeds from issuance of common shares and warrants	—			—		—			—		6,584,247			659			29,682,949			—			—		—		—		$	29,683,608
Issuance of common shares for acquisition by Cano Petro of New Mexico											404,204			40			1,853,524			—			—		—		—			1,853,564
Stock based compensation	—			—		—			—		(20,000	)		(3	)		830,086			—			—		—		—			830,083
Fortfeiture settlements	—			—		—			—		—			—			(182,881	)		—			—		—		—			(182,881	)
Preferred stock dividend	—			—		—			—		—			—			—			(3,169,516	)		—		—		—			(3,169,516	)
Net loss	—			—		—			—		—			—			—			(789,856	)		—		—		—			(789,856	)

Balance at June 30, 2007	—		$	—		—		$	—		32,688,098		$	3,268		$	85,238,490		$	(15,809,791	)	$	—		1,268,294	$	(570,732	)	$	68,861,235

See accompanying notes to these consolidated financial statements.

F-4

CANO PETROLEUM, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years Ended June 30,
				2007			2006			2005
Cash flow from operating activities:
	Net loss			$	(789,856	)	$	(1,844,424	)	$	(2,973,142	)
		Adjustments needed to reconcile net loss to net cash flow provided by (used in) operations:
			Unrealized loss on commodity derivatives		1,810,000			3,245,588			—
			Gain on sale of oil and gas properties		(3,810,589	)		—			—
			Accretion of discount on asset retirement obligations		140,129			90,492			48,204
			Depletion and depreciation		4,305,696			1,847,217			370,899
			Stock compensation expense		647,202			570,523			1,823,040
			Deferred income tax benefit		(431,000	)		(3,498,000	)		—
			Income from discontinued operations		133,416			128,675			145,379
			Amortization of debt issuance costs and prepaid expenses		2,231,468			656,382			—
	Changes in assets and liabilities relating to operations:
		Restricted cash			(6,000,000	)		—			—
		Accounts receivable			(521,492	)		(971,715	)		(489,893	)
		Derivative assets			(1,619,160	)		(6,128,402	)		—
		Prepaid expenses			(1,464,495	)		(658,814	)		—
		Inventory			28,804			(276,904	)		—
		Accounts payable			509,895			1,307,778			670,116
		Oil and gas sales payable			(232,135	)		482,853			—
		Accrued liabilities			1,101,701			(545,426	)		(74,569	)
		Taxes payable			(22,630	)		152,162			—
		Other current assets			641,453			(641,759	)		(21,069	)
		Deferred litigation credit			6,000,000			—			—

Net cash provided by (used in) operations					2,658,407			(6,083,774	)		(501,035	)

Cash flow from investing activities:
	Additions to oil and gas properties				(39,639,172	)		(5,699,133	)		(1,646,160	)
	Acquisition of New Mexico oil and gas properties				(6,552,382	)		—			(2,561,880	)
	Proceeds from sale of oil and gas properties				6,816,834			—			—
	Additions to fixed assets and other				(346,528	)		(133,318	)		(464,477	)
	Acquisition of W.O. Energy of Nevada, Inc.				—			(48,426,688	)		—
	Acquisition of additional Davenport revenue interest				(133,000	)		(700,350	)		(667,000	)
	Acquisition of Texas Panhandle oil and gas properties				—			(23,405,865	)		—
	Acquisition of Square One Energy, Inc.				—			—			(4,037,535	)
	Acquisition of Ladder Companies, Inc.				—			—			(2,215,467	)
	Cash restricted for development activities				—			—			866,339

Net cash used in investing activities					(39,854,248	)		(78,365,354	)		(10,726,180	)

Cash flow from financing activities:
	Paydown long-term debt, net				(35,250,000	)		67,323,874			—
	Payments for debt-issuance costs				(189,873	)		(654,582	)		(54,589	)
	Proceeds from issuance of preferred stock, net				45,849,138			—			5,101,231
	Proceeds from issuance of common stock, net				29,683,608			18,279,006			4,750,783
	Payment of preferred stock dividend				(1,422,593	)		—			—

Net cash from financing activities					38,670,280			84,948,298			9,797,425

Net increase (decrease) in cash and cash equivalents					1,474,439			499,170			(1,429,790	)
Cash and cash equivalents at beginning of period					644,659			145,489			1,575,279

Cash and cash equivalents at end of period				$	2,119,098		$	644,659		$	145,489

Supplemental disclosure of noncash transactions:
	Payments of preferred stock dividend in kind			$	1,746,923
	Common stock issued for acquisition of oil and gas properties			$	1,853,564		$	—		$	—
	Common stock issued for acquisition of W.O. Energy of Nevada, Inc.			$	—		$	8,240,000		$	—
	Recognition of deferred tax liability for Square One Energy, Inc.			$	—		$	3,124,013		$	—
	Preferred stock discount			$	—		$	—		$	416,534
	Common stock issued for acquisition of Square One Energy, Inc.			$	—		$	—		$	3,519,996
Supplemental disclosure of cash transactions:
	Cash paid during the period for interest			$	3,074,280		$	2,303,375		$	—

See accompanying notes to these consolidated financial statements.

F-5

CANO PETROLEUM, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cano Petroleum, Inc. (together with its direct and indirect subsidiaries, "Cano," "we," "us," or the "Company") is an independent oil and natural gas company, based in Fort Worth, Texas, that is actively pursuing waterflooding and enhanced oil recovery techniques to increase production and reserves at our existing properties and future acquisitions. Our primary focus is crude oil and our target acquisitions are onshore U.S. properties. Our focus on domestic, mature oil fields eliminates exploration risks and uncertainties of international sources.

We were originally organized under the laws of the State of Delaware on May 29, 2003 as Huron Ventures, Inc. On May 28, 2004, we entered into an Agreement and Plan of Merger with our wholly owned subsidiary, Davenport Acquisition Corp., an Oklahoma corporation; Davenport Field Unit, Inc., a Texas corporation; the shareholders of Davenport Field Unit; Cano Energy Corporation, a Texas corporation; and Big Sky Management Ltd., our then principal stockholder. Our CEO, S. Jeffrey Johnson, is a principal shareholder in Cano Energy Corporation (now THEprivate Energy Company, Inc.). Under the terms of the merger, we issued 5,165,000 shares of our common stock to the former shareholders of the Davenport Field Unit and paid $1,650,000 to fund developmental costs associated with the Davenport Field Unit and assumed debt. Pursuant to the terms of the merger, we changed our name to Cano Petroleum, Inc. on June 3, 2004. The 5,165,000 shares issued to the Davenport Field Unit shareholders are further discussed in Note 9.

Our wholly-owned subsidiaries consist of Ladder Companies, Inc., a Delaware corporation ("Ladder"); Square One Energy, Inc., a Texas corporation; W.O. Energy of Nevada, Inc. ("WO Energy), a Nevada corporation; Pantwist, LLC, a Texas limited liability corporation ("Pantwist"); and Cano Petro of New Mexico, Inc. ("Cano Petro"). Ladder wholly owns Tri-Flow, Inc., an Oklahoma corporation ("Tri-Flow"). There is no significant business transacted through Tri-Flow. WO Energy wholly owns W.O. Energy, Inc. ("WO Texas"), a Texas corporation. WO Energy and WO Texas wholly own W.O. Operating Company, Ltd. and W.O. Production Company, Ltd, both of which are Texas limited partnerships.

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

F-6

Oil and Gas Properties and Equipment

We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. All developmental costs are capitalized. We are predominately engaged in the acquisition and development of proved reserves as opposed to exploration activities. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisitions and development activity. Capitalized overhead costs that directly relate to our drilling and development activities were $532,087 and $0, for the years ended June 30, 2007 and 2006, respectively. In accordance with Statement of Accounting Standards ("SFAS") No. 34, we recorded capitalized interest costs of $302,895 and $0 for the years ended June 30, 2007 and 2006, respectively. We record capitalized interest for projects that have an expected cost of at least $1.5 million and a development period of at least six months.

Our units-of-production amortization rates are revised on a quarterly basis. 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 proved reserves associated with the projects can be determined or until impairment occurs. As of June 30, 2007 and 2006, capitalized costs related to waterflood and ASP projects that are in process and not subject to depletion amounted to $15,109,000 and $1,109,000, respectively.

At least quarterly, or more frequently 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. We had no significant unproved properties at June 30, 2007 or 2006. No impairment was necessary for the years ended June 30, 2007, 2006 or 2005.

Asset Retirement Obligation

Our financial statements reflect the fair value for any asset retirement obligation that can be reasonably estimated. The 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.

F-7

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. There were no impairments recorded for the years ended June 30, 2007, 2006 or 2005.

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.

Accounts Receivable

Accounts receivable principally consists of crude oil and natural gas sales proceeds receivable and are typically due within 35 days of their respective production. We require no collateral for such receivables, nor do we charge interest on past due balances. We periodically review accounts receivable for collectibility and reduce the carrying amount of the accounts receivable by an allowance. No such allowance was indicated at June 30, 2007 or 2006. As of June 30, 2007, our accounts receivable were primarily with several independent purchasers of our crude oil and natural gas production. At June 30, 2007, we had balances due from four customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These four customers had 26%, 26%, 25% and 10% of accounts receivable related to crude oil and natural gas production, respectively.

At June 30, 2006, we had balances due from four customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These four customers had 29%, 24%, 14% and 12% of accounts receivable related to crude oil and natural gas production, respectively.

Revenue Recognition

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 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 accounts receivable from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering systems; therefore, we do not incur transportation costs related to our sales of oil and natural gas production.

As of June 30, 2007 and 2006, we sold our crude oil and natural gas production to several independent purchasers. During the year ended June 30, 2007, we had sales of 10% or more of our total revenues to four customers which represented 36%, 18%, 17% and 16% of total operating revenue, respectively. During the year ended June 30, 2006, we had sales of 10% or more of our total revenues to five customers representing 29%, 25%, 12%, 12% and 10% of total operating revenue, respectively. During the year ended June 30, 2005, we had sales to primarily three customers which represented 58%, 21% and 19% of total operating revenue, respectively.

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

F-8

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

We began our oil and natural gas operations on May 28, 2004. Since, for the twelve months ended June 30, 2005 and the period from inception through June 30, 2004, we had incurred net losses and had not yet generated book or tax income, our consolidated statement of operations through June 30, 2005 did not reflect a provision for income taxes.

We began to record income taxes in the quarter ended December 31, 2005 as a result of the acquisition of WO Energy. This is more fully discussed in Note 11.

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.

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, 2007 and 2006. The carrying amount of long-term debt approximates market value due to the use of market interest rates.

Net Loss per Common Share

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

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

	June 30, 2007	June 30, 2006	June 30, 2005
Stock options (Note 8)	801,513	577,185	175,000
Warrants (Note 2)	1,646,061	—	—
Preferred stock (Note 2)	8,541,913	—	—
Paid-in-kind dividends (Note 2)	303,813	—	—
Restricted shares (Note 9)	95,000	2,659,975	5,165,000

The shares of common stock underlying the stock options, warrants, the preferred stock, PIK dividends and the restricted shares, as shown in the preceding table, are not included in weighted average shares outstanding for the years ended June 30, 2007, 2006 and 2005 as their effects would be anti-dilutive.

F-9

Stock Compensation Expense

Effective July 1, 2006, we accounted for share-based payments for services provided by employee to employer in accordance with SFAS No. 123(R), which generally requires companies to value the fair value of employee stock options and other equity-based compensation at the grant date and record expense over the vesting period. We adopted SFAS No. 123(R) beginning July 1, 2006. Since we had expensed stock options in accordance with SFAS No. 123, the adoption of SFAS No. 123(R) did not materially impact our operating results, financial position, or our cash flows.

Commodity Derivatives

We are required to hedge a portion of our production at specified prices for oil and natural gas under the Credit Agreement, as discussed in Note 4. The objective is to reduce our exposure to commodity price risk associated with expected oil and natural gas production. By achieving this objective we intend to protect the outstanding debt amounts and maximize the funds available under our existing Credit Agreement, which helps us to support our annual capital budgeting and expenditure plans. We have entered into commodity derivatives that set "price floors" for our crude oil and natural gas production that are recorded as derivative assets on our consolidated balance sheets and are measured at fair value.

At June 30, 2007, we have no commodity derivatives that set a price ceiling. We do not designate our derivatives as cash flow or fair value hedges. We do not hold or issue commodity derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our commodity derivatives. We anticipate, however, that our counterparty, Union Bank of California, will be able to fully satisfy their obligations under the commodity derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts subject to credit risk but we monitor the credit standing of the counterparty.

Changes in the fair values of our derivative instruments are recorded immediately in earnings as unrealized loss on commodity derivatives on our consolidated statements of operations. Cash flows resulting from the settlement of our derivative instruments are recorded as realized gains on commodity derivatives on the consolidated statements of operations.

New Accounting Pronouncements

SFAS No. 157, Fair Value Measurements, ("SFAS No. 157") was issued by the Financial Accounting Standards Board ("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. 57 applies to other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the SFAS No. 157 will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect adoption of SFAS No. 157 will have a material impact on our financial position, results of operations or cash flows.

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2. PREFERRED AND COMMON STOCK FINANCINGS

September 2006 Financing

The warrant component totals 1,646,061 common shares and is exercisable at $4.79 per share. The exercise period commenced on March 5, 2007 and expires on March 6, 2008. We computed the fair value of the warrants at September 6, 2006 as approximately $2.3 million based on the Black-Scholes model assuming the warrants will be exercised prior to the March 6, 2008 expiration date, using a 53% expected volatility factor, an expected life of 1.5 years, a risk-free rate of 4.92% and assuming no expected dividend yield. We have included the fair value of the warrants in additional paid-in capital on our consolidated balance sheet as of June 30, 2007.

Cash proceeds from the September 2006 financing were used to repay long-term debt (see Note 4), for general corporate purposes and to fund our capital expenditures.

We were required to file a Registration Statement (Form S-1) with the Securities and Exchange Commission, 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 securities on a Registration Statement Form S-3 which was declared effective on April 19, 2007. We are required to maintain the effectiveness of the registration statement, subject to certain exceptions, and if the 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. We do not believe it is probable we will incur any penalties under this provision and accordingly have not accrued any loss.

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 on or after June 6, 2007, the conversion price will be lowered to the issue or sale 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 the Series D Convertible Preferred Stock; (iii) shares issued upon exercise of the warrants issued on September 6, 2006; (iv) shares issued in connection with a firm commitment underwritten public offering with gross proceeds in excess of $50,000,000; (v) shares issued in connection with any strategic acquisition or transaction; (vi) shares issued in connection with any options or convertible securities that were outstanding on August 25, 2006; or (vii) shares issued in connection with any stock split, stock dividend, recapitalization or similar transaction.

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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 the Series D Convertible Preferred Stock shall be entitled to receive an amount per share equal to $1,000 plus dividends owing on such share prior to any payments being made to any class of capital stock ranking junior on liquidation to the Series D Convertible Preferred Stock.

In accordance with the provisions of Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity and EITF D-98 "Classification and Measurement of Redeemable Securities", the issuance of preferred stock is accounted for as temporary equity.

For the ten months ended June 30, 2007, the preferred dividend was $3,169,516, of which $1,746,923 pertained to holders of the PIK dividend option.

The liquidation preference for the preferred stock is $50,862,925, which comprises the stated value of $49,116,000 and PIK dividends of $1,746,923 as of June 30, 2007. The shares of common stock underlying the preferred stock and PIK dividends amount to 8,541,913 shares and 303,813 shares, respectively.

September 2005 Financing

In September 2005, in two private placements we issued 2,603,864 shares and 2,100,000 shares of our common stock at a per share price equal to $4.14, which was the closing price on September 13, 2005 on the American Stock Exchange. The gross and net proceeds totaled approximately $19.5 million and $18.3 million, respectively.

3. ACQUISITIONS

WO Energy—On November 29, 2005, we acquired all of the outstanding common stock of WO Energy for approximately $57.5 million, after purchase price adjustments. The purchase price consisted of approximately $48.4 million in cash (net of cash acquired) and approximately $8.24 million in restricted shares of our common stock. The approximate $8.24 million of common stock resulted in the issuance of 1,791,320 shares to the sellers based on the average of the closing price of the common stock on AMEX for the three trading days immediately prior to November 29, 2005, which was $4.60 per share. Pursuant to the original agreement, $2 million of the cash portion of the purchase price was paid into an escrow account to be kept for a minimum of two years to cover potential indemnification payments by the sellers. On June 18, 2007, the sellers deposited 434,783 shares of our common stock in exchange for the release of cash from the escrow. The escrow will be effective until the later of November 29, 2007 or the final disposition of the OneOK gas litigation that involved the sellers prior to our acquisition of WO Energy.

Pantwist—On April 28, 2006, Pantwist, our wholly-owned subsidiary, acquired certain crude oil and natural gas properties in the Texas Panhandle Field for approximately $23.5 million, after purchase price adjustments.

Cano Petro—On March 30, 2007, Cano Petro, a wholly-owned subsidiary, acquired certain oil and gas properties in the Permian Basin effective February 1, 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, which was valued at $4.59 per share. Included in the original purchase price calculation and pursuant to the agreement, $800,000 was withheld from the March 30, 2007 cash payment, which was to be ratably paid out during the following 120 days based on satisfactory completion of certain due diligence procedures. However, based on additional due diligence

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procedures we conducted subsequent to the acquisition, we paid $258,000 to satisfy the holdback obligation, and we no longer have a holdback liability as of June 30, 2007.

The acquisitions of WO Energy and the properties acquired by Pantwist and Cano Petro were recorded based on the purchase method of accounting. The operations of WO Energy, Pantwist and Cano Petro are included in our consolidated financial statements beginning December 1, 2005, May 1, 2006 and April 1, 2007, respectively. The purchase prices were allocated to the acquired assets and assumed liabilities based on their estimated fair values. The calculation of the purchase price and allocation to assets is as follows:

	WO Energy		Pantwist		Cano Petro
Net Acquisition Price	$	57,537,243	$	23,484,108	$	8,405,946
Asset Retirement Obligations		498,411		67,849		1,324,408
Deferred Tax Liability		33,228,998		—		—
Other Liabilities Assumed		1,508,762		401,973		178,625

Total Purchase Price	$	92,773,414	$	23,953,930	$	9,908,979

Allocation of Purchase Price:
Cash	$	870,376	$	—	$	—
Accounts Receivable		2,016,168		—		—
Other current assets		158,538		—		—
Fixed assets and other		4,354,556		1,258,080		35,000
Oil & Gas Properties		85,373,776		22,695,850		9,873,979

	$	92,773,414	$	23,953,930	$	9,908,979

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

The WO Energy acquisition was not eligible for the application of Section 338 in the Internal Revenue Service tax code. As defined, Section 338 would have enabled us to recognize the stepped-up basis in the WO Energy properties approximately equal to the acquisition price, for tax computation purposes. Therefore, we recorded a deferred tax liability of approximately $33.3 million (with an offsetting increase in property basis) in connection with this purchase.

Unaudited Pro Forma Financial Information. The following unaudited condensed pro forma information gives effect to the acquisitions as if they had occurred on July 1, 2005 and 2004, respectively. The pro forma financial information is not necessarily indicative of the financial results that would have occurred had the business combinations been effective on the dates indicated and should not be viewed as indicative of operations in the future.

	Years Ended June 30,
	2006			2005
Operating revenues	$	31,262,000		$	26,477,000
Earnings (loss) applicable to common stock	$	(183,000	)	$	410,000
Net earnings (loss) per share—basic and diluted	$	(0.01	)	$	0.02

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4. LONG-TERM DEBT

Credit Agreement

On November 29, 2005, we entered into a $100 million credit agreement ("Credit Agreement") with lenders led by Union Bank of California, N.A., as administrative agent and as issuing lender. Pursuant to the terms of the Credit Agreement, the borrowing base is based on our proved reserves and is redetermined every six months with one additional redetermination possible during the six month periods between scheduled redeterminations. During the quarter ended March 31, 2006, Natixis was named as a lender via an amendment to the Credit Agreement.

On March 7, 2007, we entered into an Assignment and Agreement pursuant to which (i) Union Bank of California, N.A. and Natixis adjusted their proportional lending interests; and (ii) our borrowing base was reduced from $55 million to $48 million. During June 2007, in connection with the sale of the oil and gas properties discussed in Note 6, the borrowing base was reduced to $44 million and will remain in effect until the next redetermination. On September 7, the lenders approved an increase in the borrowing base to $60.0 million.

At June 30, 2007, the outstanding amount due under the Credit Agreement was $33.5 million and is our only source of debt. The outstanding principal is due on or before November 29, 2009 unless, pursuant to the terms of the Credit Agreement, specific events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults by us, breaches of representations and warranties and covenants by us, our insolvency, a "change of control" of our business as described in the Credit Agreement and a "material adverse change" as described in the Credit Agreement.

On March 6, 2007, we entered into Amendment No. 5 to the Credit Agreement ("Amendment No. 5"). Among other items, Amendment No. 5 (i) provides that we shall grant the lenders mortgages in our Barnett Shale properties; (ii) clarifies that the development and acquisition of oil and gas properties does not constitute general corporate or working capital purposes such that expenditures for the development and acquisition of oil and gas properties are not subject to the $10 million cap on general corporate advances; (iii) provides that our Barnett Shale properties are now subject to the negative covenant of being sold without consent; and (iv) provides that the $6,000,000 of insurance proceeds received by us shall be placed in a controlled bank account to be used to pay attorney's fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation. See additional discussion at Note 12.

Subject to certain restrictions, the Credit Agreement permits the issuance of convertible notes and equity. If we are not in default under the Credit Agreement, we may make interest payments on any convertible notes and dividend payments on any preferred equity securities.

On September 7, 2007, the Leverage Ratio was amended to be as follows: (a) for each fiscal quarter ending prior to June 30, 2008, the ratio of (i) our consolidated Debt (as defined in the Credit Agreement) to (ii) the consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period then ended must not be greater than 5.00 to 1.00; (b) at the end of each fiscal quarter ending on or after June 30, 2008 but prior to December 31, 2008, the ratio shall not be greater than 4.50 to 1.00; and (c) at the end of each fiscal quarter ending on or after December 31, 2008, the ratio shall not be greater than 4.00 to 1.00. For the purposes of calculating the Leverage Ratio, the definition of "Consolidated Debt" shall not include "Debt" outstanding under preferred stock as discussed in Note 2. We were in compliance with the prior Leverage Ratio of not greater than 5.00 to 1.00 as of June 30, 2007.

In the Credit Agreement, the Interest Coverage Ratio is as follows: (i) for the quarter ending September 30, 2006, the ratio of our consolidated EBITDA for the two quarter period multiplied by two to our consolidated Interest Expense for the two quarter period multiplied by two must be at least

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1.25 to 1.00; (ii) for the quarter ending December 31, 2006, the ratio of our consolidated EBITDA for the three quarter period multiplied by ⁴/3 to our consolidated Interest Expense for the three quarter period multiplied by ⁴/3 must be at least 1.25 to 1.00; (iii) for the quarter ending March 31, 2007, the ratio of our consolidated EBITDA for the four quarter period to our consolidated Interest Expense for the four quarter period must be at least 1.50 to 1.00; and (iv) for any quarter ending on or after June 30, 2007, the ratio of our consolidated EBITDA for the four fiscal quarters then ended to our consolidated Interest Expense for the four fiscal quarters then ended must be at least 2.00 to 1.00. The definition of "Interest Expense" shall include cash dividends paid under our preferred stock, but shall exclude PIK dividends under preferred stock, as discussed in Note 2. We were in compliance with the Interest Coverage Ratio as of June 30, 2007.

At our option, interest is based either (i) on the prime rate plus the applicable margin ranging up to 1.00% based on the utilization level or (ii) on the LIBOR rate applicable to the interest period plus the applicable margin ranging from 1.75% to 2.50% based on the utilization level. At June 30, 2007 and 2006, the interest rate was 7.46% and 8.49%, respectively. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.

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

In addition, we are required to hedge our exposure to commodity price risk associated with expected oil and natural production. The Credit Agreement requires the hedges to cover no less than 50% and no more than 80% of the production volumes attributable to our proved producing reserves. Our commodity derivatives are further discussed in Note 5.

Subordinated Credit Agreement

On November 29, 2005, we entered into a $15.0 million subordinated credit agreement with the lenders led by Energy Components SPC EEP Energy Exploration and Production Segregated Portfolio, as administrative agent. As previously discussed, during September 2006, cash proceeds from the September 2006 financing discussed in Note 2 were used to repay $68.75 million of outstanding long-term debt, consisting of amounts due under the Credit Agreement and subordinated credit agreement of $53.75 million and $15.0 million, respectively. Due to repaying the $15.0 million outstanding balance on the subordinated credit agreement, this debt facility was permanently retired.

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5. COMMODITY DERIVATIVES

During our years ended June 30, 2007 and 2006, we paid $1.6 million and $6.1 million to enter into financial contracts to set price floors. These financial contracts are summarized in the table below.

Time Period	Floor Oil Price		Barrels per Day	Floor Gas Price		Gas Mcf per Day	Barrels of Equivalent Oil per Day
1/1/06 - 12/31/06	$	60	534	$	8.50	1,784	832
6/1/06 - 12/31/06	$	60	79	$	7.60	690	194
1/1/07 - 12/31/07	$	55	507	$	8.00	1,644	781
1/1/07 - 12/31/07	$	60	72	$	7.60	658	182
1/1/08 - 12/31/08	$	55	479	$	7.50	1,534	735
1/1/08 - 12/31/08	$	60	66	$	7.60	592	164
1/1/09 - 4/30/09	$	60	59	$	7.60	559	152
1/1/09 - 12/31/09	$	55	395	$	7.60	1,644	668
1/1/10 - 6/30/10	$	55	365	$	7.00	1,657	641

During the years ended June 30, 2007 and 2006, there were settlements under our commodity derivatives due to us amounting to $962,559 and $540,871, respectively, which are recorded as realized gain on commodity derivatives on our consolidated statements of operations. The settlements were cumulative monthly payments due to us since the NYMEX natural gas price was lower than the "floor natural gas prices" ranging between $7.60 and $8.50 and the WTI-NYMEX oil price was lower than the "floor oil prices" ranging from $55 to $60. The cash flows relating to the derivative instruments are reflected in operating activities on our consolidated statements of cash flows. At June 30, 2007 and 2006, we had amounts due from our counterparty of $70,610 and $161,173, respectively, included in our accounts receivable in our consolidated balance sheets.

6. DISCONTINUED OPERATIONS

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 $6.9 million. The agreement had an effective date of April 1, 2007. All of the funds received were used to reduce the outstanding balance under the Credit Agreement discussed in Note 4.

The results of operations of the Rich Valley Properties, effective April 1, 2007, have been presented as discontinued operations in the accompanying consolidated statements of operations. Prior year results have also been reclassified to report the results of operations of the Rich Valley Properties

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sold as discontinued operations. Results for these assets reported as discontinued operations were as follows:

			Years Ended June 30,
			2007		2006		2005
Operating Revenues:
	Crude oil and natural gas sales		$	1,409,747	$	2,006,353	$	1,717,625
Operating Expenses:
	Lease operating			548,138		624,529		661,198
	Production and ad valorem taxes			99,166		141,645		119,230
	General and administrative			159,575		171,065		75,477
	Accretion of asset retirement obligations			13,820		17,241		21,610
	Depletion and depreciation			119,596		111,434		123,769
	Interest expense, net			147,956		181,876		—

		Total operating expenses		1,088,251		1,247,790		1,001,284

Gain on sale of properties				3,810,589		—		—

Income before taxes				4,132,085		758,563		716,341
Income tax provision				1,487,551		273,083		—

Income from discontinued operations			$	2,644,534	$	485,480	$	716,341

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.

As of April 1, 2007, the assets of the Rich Valley Properties totaled $3.3 million, of which $3.2 million represented the oil and gas properties, net. At June 30, 2006, the Rich Valley Properties' assets totaled $3.4 million, of which $3.2 million represented oil and gas properties, net.

7. RELATED PARTY TRANSACTIONS

Transactions involving Directors

On March 29, 2005, we entered into an agreement with Haddock Enterprises, LLC and Kenneth Q. Carlile (predecessor to Carlile Management, LLC) to explore the possibility of converting the Sabine Royalty Trust from a liquidating asset into a vehicle to acquire low risk assets. Each of the three parties owned a one-third interest in the Sabine Production Operating, LLC ("Sabine Production"). Gerald W. Haddock is President of Haddock Enterprises, LLC and is a member of our Board of Directors. From inception through of June 30, 2006, we had incurred approximately $420,000 pertaining to the joint venture, of which $325,000 was funded directly to Sabine Production. During the years ended June 30, 2006 and 2005, we incurred $380,000 and $40,000, respectively, which we charged to general and administrative expense.

On January 26, 2007 but effective January 8, 2007, we entered into an amendment to the agreement that provides the maximum amount to be committed to Sabine Production by any member was increased from $325,000 to $375,000. The amendment also provides that after funding the increased commitment of $375,000, a member may withdraw as a member of Sabine Production. Upon a withdrawal, the withdrawing member forfeits its membership interests in Sabine Production and is released from all of its obligations under the agreement. On January 26, 2007, we made our final contribution of $50,000 to Sabine Production such that our aggregate contribution was $375,000 and on February 1, 2007, we delivered our notice of withdrawal from Sabine Production effective on February 1, 2007.

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We have entered into an agreement to be a lead sponsor of a television production called Honey Hole All Outdoors. As part of our sponsorship, we are able to provide fishing and outdoor opportunities for children with cancer, children from abusive family situations, and military veterans. During the years ended June 30, 2007 and 2006, we paid $150,000 and $125,000, respectively, to R.C. Boyd Enterprises, the owner of Honey Hole All Outdoors. Randall Boyd is the sole shareholder of R.C. Boyd Enterprises and is a member of our Board of Directors.

Transactions involving THEprivate Energy Company

On December 27, 2005, we acquired all overriding royalty interests held by THEprivate Energy Company, Inc. (formerly Cano Energy Corporation) effective as of December 1, 2005, and we are to acquire all overriding royalty interests acquired in the future by THEprivate Energy Company, Inc. in and to the crude oil, natural gas and mineral leaseholder estates and personal property related to leasehold estates located on the same property on which the Davenport Field Unit's properties are located. We paid $66,700 per percentage of net revenue attributable to the interests held by THEprivate Energy Company, Inc. During December 2005, we paid $500,250 to acquire a 7.5% overriding royalty interest and during January 2006, we paid $200,100 to acquire a 3.0% overriding royalty interest. At June 30, 2006, we had accrued $133,400 to acquire an additional 2.0% overriding royalty interest and consummated the transaction during August 2006.

S. Jeffrey Johnson, our Chairman of the Board and Chief Executive Officer, is a 30% shareholder in THEprivate Energy Company, Inc. The terms of the purchase were supported by a valuation established by our independent engineer. This purchase was approved by our Board of Directors.

8. STOCK OPTION PLANS

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

On December 16, 2004, we issued stock options for 50,000 shares of our common stock to Gerald Haddock, a current member of our board of directors, in exchange for certain financial and management consulting services to us. The exercise price is $4 per share. The options are exercisable at any time, in whole or in part, during the ten-year option period which commenced six months following the date of grant (June 16, 2005) and 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. The options granted under the Plan totaled 125,000 shares. These options have an exercise price of $4.13 per share. The options vested on April 1, 2006, and expire on April 1, 2015. During the year ended June 30, 2007, 25,000 options shares were exercised and 25,000 option shares were forfeited. As of June 30, 2007, these vested options totaled 75,000 shares.

On September 16, 2005, we granted stock options to James K. Teringo, Jr., then our Senior Vice President, General Counsel and Corporate Secretary to purchase 50,000 shares of common stock. These options have an exercise price of $3.98 per share. These options were forfeited during May 2007.

On December 7, 2005, our stockholders approved our 2005 Long-Term Incentive Plan ("2005 LTIP") that authorized the issuance of up to 1,000,000 shares of our common stock to key employees, key consultants and outside directors of our company and subsidiaries. On December 28, 2006, our stockholders approved an amendment to the 2005 LTIP that increases the number of shares authorized for issuance from 1,000,000 to 3,500,000 shares of our common stock. The amendment also increases for Executive Officers (as defined in the Plan) for any calendar year (i) the number of stock options or stock appreciation rights that any Executive Officer can receive from 100,000 shares of common stock to 300,000 shares of common stock, (ii) the number of shares relating to restricted stock, restricted stock units, performance awards or other awards that are subject to the attainment of performance

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goals that any Executive Officer can receive from 100,000 shares of common stock to 300,000 shares of common stock; and (iii) the number of shares relating to all awards that an Executive Officer can receive from 100,000 to 300,000. The 2005 LTIP permits the grant of incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, dividend equivalent rights and other awards, whether granted singly, or in combination or in tandem. 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.

On December 13, 2005, under the 2005 LTIP, 25,000 options were granted to each of our five non-employee directors. The options granted to our directors under the 2005 LTIP totaled 125,000 shares. The exercise price is $6.30 per share. These granted options vested on December 13, 2006 if such persons were still directors or an employee on December 13, 2006. As of June 30, 2007, these vested options totaled 125,000 shares.

During April 2006 and June 2006, we granted options totaling 227,185 shares to our employees under the 2005 LTIP. In April 2006, options totaling 90,000 shares were granted and the exercise price was $9.55 per share. These 90,000 option shares have been forfeited. On June 21, 2006, options totaling 137,185 shares were granted and vest on June 21, 2009, with an exercise price of $5.15 per share. As of June 30, 2007, 29,975 of these option shares have been forfeited.

On August 11, 2006, under the 2005 LTIP, 15,000 options were granted to each of two non-employee directors. The options granted to these two directors under the 2005 LTIP totaled 30,000 shares. The exercise price is $5.06 per share. These granted options would have vested on August 11, 2007 if such persons were still directors or an employee on this date. As of June 30, 2007, the 30,000 options were forfeited.

On December 28, 2006, under the 2005 LTIP, 25,000 options were granted to each of our six non-employee directors totaling 150,000 shares. The exercise price is $5.42 per share. These granted options vest on December 28, 2007 if such persons are still directors or an employee on December 28, 2007. As of June 30, 2007, 50,000 of these options were forfeited.

On December 28, 2006, under the 2005 LTIP, we granted 265,000 total options to our five executive officers. The exercise price is $5.42 per share. If the executive officer is still employed by us on each anniversary date of the grant, one-third of the stock options will vest on each of the following three anniversary dates—December 28, 2007, 2008 and 2009. As of June 30, 2007, 40,000 of these options were forfeited.

On February 7, 2007, under the 2005 LTIP, we granted 12,000 total options to an employee. The exercise price is $4.88 per share. The options vest on February 7, 2010 if such person is still an employee on February 7, 2010.

On April 4, 2007, under the 2005 LTIP, we granted 61,803 total options to three non-employee directors. The exercise price is $4.73 per share. The options vest on December 28, 2007 if such persons are still directors or an employee on December 28, 2007.

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. On June 29, 2007, Dr. James Underwood resigned as a director; therefore, his unvested stock options vested on June 29, 2007 and the exercise period for his options was extended to June 29, 2009.

On June 30, 2007, under the 2005 LTIP, we granted 45,500 total options to several employees. The exercise price is $6.15 per share. The options vest on June 30, 2010 if such person is still an employee on June 30, 2010.

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A summary of options we granted during the years ended June 30, 2007, 2006 and 2005 are as follows:

	Shares		Weighted Average Exercise Price
Outstanding at July 1, 2004	—			—
Shares granted	175,000		$	4.09
Shares exercised, forfeited, or expired during fiscal year	—			—

Outstanding at June 30, 2005	175,000		$	4.09
Shares granted	402,185		$	6.35
Shares exercised, forfeited, or expired during fiscal year	—			—

Outstanding at June 30, 2006	577,185		$	5.66
Shares granted	564,303		$	5.37
Shares forfeited or expired	(314,975	)	$	6.21
Shares exercised	(25,000	)	$	4.13

Outstanding at June 30, 2007	801,513		$	5.29

The following is a summary of stock options outstanding at June 30, 2007:

Exercise Price		Options Outstanding	Remaining Contractual Lives (Years)	Options Exercisable
$	4.00	50,000	7.96	50,000
$	4.13	75,000	7.76	75,000
$	4.73	61,803	9.50	—
$	4.88	12,000	9.62	—
$	5.15	107,210	8.98	—
$	5.42	325,000	9.50	—
$	6.15	45,500	10.00	—
$	6.30	125,000	8.46	125,000

$	5.29	801,513	9.18	250,000

Based on our $6.00 stock price at June 30, 2007, the intrinsic value of the options outstanding was approximately $612,000.

Total options exercisable at June 30, 2007 amounted to 250,000 shares and had a weighted average exercise price of $5.19. Upon exercise, we issue the full amount of shares exercisable per the term of the options from new shares. We have no plans to repurchase those shares in the future. The following is a summary of options exercisable at June 30, 2007, 2006 and 2005:

	Shares	Weighted Average Exercise Price
June 30, 2007	250,000	$	5.19
June 30, 2006	220,000	$	5.21
June 30, 2005	50,000	$	4.00

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

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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.

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,
	2007		2006		2005
No. of shares		564,303		402,185		175,000
Risk free interest rate		4.56 - 4.91%		4.03 - 5.15%		4.02 - 4.27%
Expected life		4 years		4 years		4 years
Expected volatility		50.5 - 53.4%		46.3 - 51.9%		41.9 - 51.5%
Expected dividend yield		0%		0%		0%
Weighted average grant date fair value—exercise prices equal to market value on grant date	$	2.64	$	2.47	$	—
Weighted average grant date fair value—exercise prices greater than market value on grant date		2.44	$	2.71	$	—
Weighted average grant date fair value—exercise prices less than market value on grant date	$	—	$	—	$	1.73

For the years ended June 30 2007, 2006 and 2005, we have recorded a charge to stock compensation expense of $587,259, $563,330 and $144,255, respectively, for the estimated fair value of the options granted to our directors and employees.

9. DEFERRED COMPENSATION

Management Stock Pool Agreement

Pursuant to the terms of a Management Stock Pool Agreement dated May 28, 2004, the 5,165,000 shares issued to the Davenport Field Unit shareholders were placed in escrow, and were scheduled to be released from escrow pursuant to the achievement of certain employment and performance goals.

The Davenport Field Unit shareholders were comprised of three current employees, four former employees and one director. The shares vested to the individuals based on a combination of continued employment ("compensation shares") and achieving certain performance goals during the two years following the merger ("performance shares"). The compensation shares amounted to 2,659,975 shares and the performance shares amounted to 2,505,025 shares. Any shares not released from escrow were returned to treasury stock. At the merger date, we recognized $2,324,250 of deferred compensation in the consolidated balance sheets. The shares were recorded based on the quoted market price at the time of the transaction.

During the year ended June 30, 2006, of the total compensation shares, 2,644,192 shares were released and 15,783 compensation shares were forfeited by a former employee. During October 2006, the Board approved the release of performance shares totaling 1,252,514 shares to the executive Davenport shareholders and the remaining 1,252,511 shares were returned as treasury shares.

As of June 30, 2007, the treasury stock totaled 1,268,294 shares, consisting of the 1,252,511 performance shares which have been returned as treasury stock and 15,783 compensation shares forfeited by a former employee.

The $2,324,250 of deferred compensation that was recognized on the merger date was based on management's expectation that all escrowed shares would be released from escrow. We have adjusted the expense to be recorded as deferred compensation, for the year ended June 30, 2006, to match the

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actual award of escrowed shares totaling 3,896,706 shares (2,644,192 compensation shares and 1,252,514 performance shares). Accordingly, of the $2,324,250 recognized as deferred compensation, we recognized total expense of $1,753,518 from our inception through June 30, 2006, of which $1,775,629 was recognized prior to June 30, 2005. The remaining 1,268,294 shares were returned as treasury shares, at a recognized cost of $570,732.

Once the Board made its final determination of the performance shares awarded in October 2006, the Management Stock Pool Agreement expired and had no effect to the financial statements for the year ended June 30, 2007.

Contingently Issued Shares from the 2005 Long-Term Incentive Plan

During June 2006, 140,000 restricted shares were issued to key employees from our 2005 LTIP, previously discussed in Note 8. During the year ended June 30, 2007, forfeited shares totaled 50,000 shares and 5,000 additional shares were granted. As of June 30, 2007, the outstanding 95,000 restricted shares are summarized below:

	Shares		Weighted Average Grant-Date Fair Value		Fair Value
Outstanding at June 30, 2006	140,000		$	5.62	$	786,800
Shares granted during August 2006	5,000		$	5.03	$	25,150
Shares forfeited during November 2006 and May 2007	(50,000	)	$	5.62	$	(281,000	)

Outstanding at June 30, 2007	95,000		$	5.59	$	530,950

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 our actual stock price on the date of grant multiplied by the number of restricted shares granted. As of June 30, 2007, the value of non-vested restricted shares amounted to $418,550. In accordance with SFAS No. 123(R), for the year ended June 30, 2007 and 2006, we have expensed $242,824 and $29,304, respectively, to stock compensation expense based on amortizing the fair value over the appropriate service period.

Subsequent to June 30, 2007, we awarded 395,000 restricted shares to executive officers with a grant date of July 2, 2007. Such shares vest in three equal increments on the first, second and third anniversaries of the grant date. The grant date fair value per share was $5.84 per share, or $2,306,800 aggregated. Such amount will be recognized in expense over the three-year vesting period.

10. ASSET RETIREMENT OBLIGATION

Our asset retirement obligation ("ARO") primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our ARO by calculating the present value of estimated cash flows related to the liability. At June 30, 2007, our liability for ARO was $2,415,070, of which $2,150,930 was considered long term. At June 30, 2006, our liability for ARO was $1,607,378, of which $1,587,569 was considered long term. Our asset retirement obligations are recorded as current or non-current liabilities based on the estimated timing of the anticipated cash flows. For the years ended June 30, 2007, 2006, and 2005, we have recognized accretion expense, net of discontinued operations discussed in Note 6, of $140,129, $90,492 and $48,204, respectively.

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The following table describes the changes in our asset retirement obligations for the years ended June 30, 2007 and 2006:

Asset retirement obligation at July 1, 2005		$	1,051,453
Liabilities incurred:
	Acquisition of WO Energy		498,411
	Properties acquired by Pantwist		67,849
Accretion expense			107,733
Liabilities settled			(118,068	)

Asset retirement obligation at June 30, 2006		$	1,607,378
Liabilities incurred:
	Liability incurred for properties acquired (Note 3)		1,324,408
	Sale of Rich Valley—Discontinued Operations (Note 6)		(254,020	)
	Accretion expense		140,129
	Liabilities settled		(17,855	)
	Change in estimate		(384,970	)

Asset retirement obligation at June 30, 2007		$	2,415,070

The amounts listed above include the effects of purchase accounting adjustments to reflect knowledge gained since we assumed operational responsibilities of these properties. The change in estimate resulted primarily from an increase in productive years for certain fields.

11. 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 benefit is as follows:

			Years Ended June 30,
			2007			2006			2005
Current income tax benefit
	Federal		$	—		$	—		$	—
	State			53,000			—			—

		Total current tax benefit		—			—			—

Deferred income tax benefit
	Federal			(1,857,000	)		(1,877,000	)		—
	State			(115,000	)		(1,894,000	)		—

		Total deferred tax benefit		(1,972,000	)		(3,771,000	)		—

Total income tax benefit			$	(1,919,000	)		(3,771,000	)	$	—

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A reconciliation of the differences between our applicable statutory tax rate and our effective income tax rate for the years ended June 30, 2007, 2006 and 2005 is as follows:

		Years Ended June 30,
		2007			2006			2005
Rate			35	%		35	%		35	%
Tax at statutory rate		$	(1,873,000	)	$	(2,135,000	)	$	(1,292,000	)
State taxes			—			(61,000	)		(96,000	)
Increase (decrease) resulting from:
	Change in Texas tax law		(84,000	)		(1,840,000	)		—
	Permanent and other		16,000			31,000			11,000
	Change in valuation allowance		22,000			234,000			1,377,000

Income tax benefit		$	(1,919,000	)	$	(3,771,000	)		—

A schedule showing the significant components of the net deferred tax liability as of June 30, 2007 and 2006 are as follows:

			As of June 30,
			2007			2006
Deferred tax assets:
	Deferred compensation expense		$	1,143,000		$	834,000
	Net operating loss carryovers			4,615,000			4,680,000
	Other			200,000			216,000

				5,958,000			5,730,000
Less: valuation allowance				(770,000	)		(792,000	)

	Total deferred tax assets			5,188,000			4,938,000
Deferred tax liabilities—
	Difference in book and tax bases:
		Acquired oil and gas properties		(36,078,000	)		(35,950,000	)
		Other properties		(1,481,000	)		(499,000	)

		Total deferred tax liabilities		(37,559,000	)		(36,449,000	)

Net deferred tax liability			$	(32,371,000	)	$	(31,511,000	)

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. Therefore, we recalculated our deferred tax assets and liabilities for Texas based upon the new margin tax and recorded a $1,840,000 deferred tax benefit for the Texas margin tax in 2006.

At June 30, 2007 and 2006, we had net operating loss ("NOL") carryforwards for tax purposes of approximately $12.8 million and $13.0 million. The remaining net operating losses principally expire between 2024 and 2027. $2.2 million of these NOL carryforwards will be unavailable to offset any future taxable income due to limitations from change in ownership as defined in Section 382 of the Internal Revenue Service code. The tax effect of this limitation is recorded as a valuation allowance of $770,000 and $792,000 at June 30, 2007 and 2006, respectively.

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12. COMMITMENTS AND CONTINGENCIES

Fire Litigation

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is underway and the case is set for trial on October 29, 2007. On August 28, 2007, one of the intervenors, Travelers Lloyds Insurance Company, filed a Notice of Nonsuit requesting the court to sign an order dismissing its claims, which seek approximately $367,627 of total damages, without prejudice.

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Insurance Settlement

On February 9, 2007, Cano and its subsidiaries entered into a Settlement Agreement and Release with the plaintiff pursuant to which in exchange for mutual releases, in addition to the approximately $923,000 that we have been reimbursed by plaintiff, the plaintiff agreed to pay to Cano within 20 business days of February 9, 2007 the amount of $6,699,827 comprised of 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, in accordance with the Credit Agreement (Note 4), have been placed in a controlled bank account and the use of the proceeds is specified to pay attorney's fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation. Accordingly, our consolidated balance sheets reflect the $6,000,000 as restricted cash and a corresponding liability under deferred litigation credit. The remaining $699,827 was applied as a reduction to general and administrative expense for litigation expenses incurred.

Other

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

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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.

Leases

During June 2006, we entered into a non-cancelable operating lease for our principal executive offices in Fort Worth. The lease expires on April 20, 2011. Our total obligation for the life of the lease is $1,490,584. In addition, during October 2005 we entered into a five year operating lease for our field offices at WO Energy. The lease expires on November 29, 2010. Future minimum rentals due under our non-cancellable operating leases were as follows on June 30, 2007:

		2008			2009			2010			2011			Total
Total operating lease obligations		$	436,397		$	438,422		$	425,875		$	334,165		$	1,634,859

Rent expense amounted to $339,697, $98,000, and $107,868 for the years ended June 30, 2007, 2006 and 2005, respectively.

Employment Contracts

We have an employment contract with our CEO that requires minimum compensation totaling $476,000 annually through December 31, 2010. Our Senior Vice President and Chief Financial Officer has an employment contract through May 31, 2010 that provides for minimum compensation of $300,000 annually. Our Senior Vice-President of Operations employment contract is through May 31, 2010 that provides for minimum compensation of $250,000 annually. Our Vice President and Principal Accounting Officer has an employment contract through June 30, 2010 that provides for minimum compensation of $187,000 annually.

13. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

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,
		2007			2006
Mineral interests in oil and gas properties:
	Proved	$	97,709,489		$	89,027,955
	Unproved		—			1,500,025
Wells and related equipment and facilities			70,618,844			41,539,638
Support equipment and facilities used in oil and gas producing activities			6,405,549			4,890,023
Uncompleted wells, equipment and facilities			15,109,000			1,109,000

Total capitalized costs			189,842,882			138,066,641
Less accumulated depreciation and amortization			(6,201,635	)		(2,319,780	)

Net Capitalized Costs		$	183,641,247		$	135,746,861

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Costs Incurred in Oil and Gas Producing Activities

	Years Ended June, 30
	2007		2006		2005
Acquisition of proved properties	$	9,873,979	$	108,725,132	$	12,444,875
Acquisition of unproved properties		—		21,932		1,478,093
Development costs		41,902,262		12,649,715		1,984,894
Asset retirement costs recognized according to SFAS No. 143		17,855		118,068		27,787

Total Costs Incurred	$	51,794,096	$	121,514,847	$	15,935,649

Results of Operations from Oil and Gas Producing Activities

	Years Ended June 30,
	2007			2006			2005
Oil and gas revenues	$	28,353,026		$	15,860,562		$	3,764,015
Production costs		(10,885,393	)		(6,240,986	)		(2,068,881	)
Production taxes		(2,465,191	)		(1,153,775	)		(223,566	)
Depreciation and accretion		(4,312,409	)		(1,809,034	)		(273,724	)
Realized gain on hedge contracts		962,559			540,871			—
Unrealized loss on hedge contracts		(1,810,000	)		(3,245,588	)		—

Results of oil and gas producing operations before income taxes	$	9,842,592		$	3,952,050		$	1,197,844
Provision for income taxes*		(3,543,333	)		(1,462,259	)		—
Income from discontinued operations, net of tax		2,644,534			485,480			716,341

Results of Oil and Gas Producing Operations	$	8,943,793		$	2,975,271		$	1,914,185

*: Since we did not have a provision for federal income taxes for 2005, we did not compute a tax provision for the disclosure listed above.

Proved Reserves

Our proved oil and natural gas reserves have been estimated by independent petroleum engineers. 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 oil

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and natural gas properties; and changes in economic factors. Our proved reserves are summarized in the table below.

	Crude Oil Bbls.		Natural Gas Mcf
Reserves at June 30, 2004	213,245		—
Purchases of minerals in place	2,066,456		9,531,352
Revisions of prior estimates	865,587		1,036,629
Production	(89,308	)	(180,069	)

Reserves at June 30, 2005	3,055,980		10,387,912

Proved developed reserves	2,989,514		10,019,094
Reserves at June 30, 2005	3,055,980		10,387,912
Purchases of minerals in place	29,733,098		75,840,658
Revisions of prior estimates	1,270,383		(16,421,342	)
Production	(191,700	)	(705,183	)

Reserves at June 30, 2006	33,867,761		69,102,045

Proved developed reserves	6,983,925		23,527,860
Reserves at June 30, 2006	33,867,761		69,102,045
Purchases of minerals in place	7,756,858		8,158,734
Extensions and discoveries	—		64,940,035
Sale of minerals in place	(216,308	)	(2,132,618	)
Revisions of prior estimates	1,204,567		7,712,363
Production	(283,054	)	(1,440,894	)

Reserves at June 30, 2007	42,329,824		146,339,665

Proved developed reserves	6,554,961		28,450,252

The base prices used to compute the crude oil and natural gas reserves represent the NYMEX oil and natural gas prices at June 30, 2007, 2006 and 2005, 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. For the reserves at June 30, 2006, the crude oil and natural gas prices were $73.94 per barrel and $5.83 per MMbtu, respectively. For the reserves at June 30, 2005, the crude oil and natural gas prices were $56.54 per barrel and $6.98 per MMbtu, respectively.

For the reserves at June 30, 2007 and 2006, the purchases of minerals in place pertain to our acquisitions of oil and natural gas properties, which are discussed in greater detail at Note 3.

For the reserves at June 30, 2006, the above table identifies a 16,422,506 Mcf reduction in natural gas reserves for revisions of prior estimates. Approximately 7,200,000 Mcf pertains to renegotiation of a natural gas purchase contract that was not finalized at June 30, 2006; therefore, these reserves were excluded at June 30, 2006, but were included in the reserve at June 30, 2007 since the natural gas purchase contract was finalized. The remaining 9,224,523 Mcf reduction is primarily due to the reassessment of natural gas production from the planned waterflood implementation in the Panhandle Field.

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.

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Standardized Measure

The standardized measure of discounted future net cash flows ("standardized measure") and changes in such cash flows are prepared using assumptions required by the FASB. Such assumptions include 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% rate.

As of June 30, 2007, 2006 and 2005, 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 and proved undeveloped reserve additions attributable to increased development activity.

Standardized Measure of Discounted Future Cash Flows:

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, 2007, 2006 and 2005 is as follows:

	2007			2006			2005
Future cash inflows	$	3,902,164,000		$	2,812,728,000		$	222,665,000
Future production and development costs		(1,258,325,000	)		(893,798,000	)		(123,360,000	)
Future income taxes		(920,000,000	)		(694,500,000	)		(31,606,000	)

Future net cash flows		1,723,839,000			1,224,430,000			67,699,000
10% annual discount		(1,022,808,000	)		(881,966,000	)		(37,160,000	)

Standardized measure of discounted future net cash flows	$	701,031,000		$	342,464,000		$	30,539,000

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Changes in Standardized Measure of Discounted Future Cash Flows:

The primary changes in the standardized measure of discounted estimated future net cash flows for the years ended June 30, 2007, 2006 and 2005 are as follows:

	2007			2006			2005
Balance at beginning of year	$	342,464,000		$	30,539,000		$	1,500,000
Net changes in prices and production costs		(7,186,000	)		32,650,000			315,000
Net changes in future development costs		(91,588,000	)		(48,006,000	)		(1,680,000	)
Sales of oil and gas produced, net		(15,765,000	)		(10,247,000	)		(2,409,000	)
Purchases of reserves		174,645,000			575,835,000			43,280,000
Sales of reserves		(10,953,000	)		—			—
Extensions and discoveries		207,340,000			—			—
Revisions of previous quantity estimates		47,699,000			(19,929,000	)		2,164,000
Previously estimated development costs incurred		43,802,000			7,760,000			1,985,000
Net change in income taxes		(97,089,000	)		(213,131,000	)		(14,833,000	)
Accretion of discount		57,043,000			3,054,000			233,000
Other		50,619,000			(16,061,000	)		(16,000	)

Balance at end of year	$	701,031,000		$	342,464,000		$	30,539,000

14. SELECTED QUARTERLY DATA (UNAUDITED)

	30-Sep			31-Dec			31-Mar			30-Jun
Fiscal Year Ended June 30, 2007
Operating revenues from continuing operations	$	7,674,800		$	6,157,932		$	5,883,454		$	8,636,840
Operating income (loss) from continuing operations		133,478			(424,659	)		(1,587,287	)		(320,439	)
Loss from continuing operations		(442,914	)		(530,281	)		(2,250,689	)		(210,507	)
Income from discontinued operations, net of tax		75,021			85,103			59,559			2,424,851
Net income (loss) applicable to common stock		(636,492	)		(1,412,149	)		(3,158,102	)		1,247,372
Net income (loss) per share—basic and diluted		(0.02	)		(0.04	)		(0.10	)		0.04
Fiscal Year Ended June 30, 2006
Operating revenues from continuing operations	$	1,541,874		$	2,625,499		$	4,835,493		$	6,857,696
Operating income (loss) from continuing operations		(696,335	)		(691,401	)		39,201			254,119
Net income (loss) from continuing operations		(610,373	)		(1,656,251	)		(1,207,722	)		1,144,442
Income from discontinued operations, net of tax		152,416			169,715			76,694			86,655
Net income (loss) applicable to common stock		(457,957	)		(1,486,536	)		(1,131,028	)		1,231,097
Net income (loss) per share—basic and diluted		(0.02	)		(0.06	)		(0.05	)		0.05