Item 1A. Risk Factors.
Our business involves a high degree of risk. Investors should carefully consider the risks and uncertainties described below. Each of the following risks may materially and adversely affect our business, results of operations and financial condition. These risks may cause the market price of our common stock to decline, which may cause you to lose all or a part of the money you paid to buy our common stock.
Risks Related to Our Industry
Crude oil and natural gas prices are volatile. A substantial or sustained decline in prices could adversely affect our financial position, financial results, cash flows and access to capital.
Our revenues and operating results depend primarily upon the prices we receive for the crude oil and natural gas we produce and sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Historically, the markets for crude oil and natural gas have been volatile and they are likely to continue to be volatile. The prices we receive for our crude oil and natural gas are based upon factors that are beyond our control, including:
· worldwide and domestic demands and supplies of oil and natural gas;
· weather conditions;
· the price and availability of alternative fuels;
· the availability of pipeline capacity;
· the price and level of foreign imports;
· domestic and foreign governmental regulations and taxes;
· the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
· political instability or armed conflict in oil-producing regions; and
· the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future crude oil and natural gas price movements with any certainty. Declines in crude oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves.
Government regulation may adversely affect our business and results of operations.
Oil and natural gas operations are subject to various and numerous federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, spacing of wells, injection of substances, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. Certain federal, state and local laws and regulations applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations, exist for the purpose of protecting the human health and the environment. The transportation and storage of refined products include the risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies and private parties for natural resources damages, personal injury, or property damages and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined and unrefined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. As a result, we may incur substantial expenditures and/or liabilities to third parties or governmental entities which could have a material adverse effect on us.
The oil and natural gas industry is capital intensive, and we may not be able to raise the capital needed to conduct our operations as planned or to make strategic acquisitions.
The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition of, exploration for and development of, crude oil and natural gas reserves. Due to our current liquidity constraints, it is unlikely that we will make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future.
Historically, we have financed capital expenditures with cash generated by operations, proceeds from bank borrowings and sales of equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:
· our proved reserves;
· the level of oil and natural gas we are able to produce from existing wells;
· the prices at which oil and natural gas are sold; and
· our ability to acquire, locate and produce new reserves.
Any one of these variables can materially affect our ability to access the capital markets.
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to fund future development projects. We may, from time to time, seek additional financing, either in the form of bank borrowings, public or private sales of debt or equity securities or other forms of financing, or consider selling non-core assets to raise additional operating capital. However, we may not be able to obtain additional financing or sell non-core assets upon terms acceptable to us.
Any prolonged, substantial reduction in the demand for oil and gas, or distribution problems in meeting this demand, could adversely affect our business.
Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. We may also have to shut-in some of our wells temporarily due to a lack of market or adverse weather conditions. If the demand for oil and gas diminishes, our financial results would be negatively impacted.
In addition, there are limitations related to the methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production, any of which could have a negative impact on its results of operation and cash flows.
Environmental liabilities could adversely affect our financial condition.
The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:
· well drilling or workover, operation and abandonment;
· waste management;
· land reclamation;
· financial assurance under the Oil Pollution Act of 1990; and
· controlling air, water and waste emissions.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs of
production, development or exploration, or decreased production, and may affect our costs of acquisitions.
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 if it is damaged as a result of a blow-out. We have “an “Owned-Hired and Non-Owned” Commercial Automobile liability limit of $1,000,000. We also have secured $50,000,000 umbrella coverage in excess of the general liability and automobile liability. There is a $2,000,000 policy for control of well, redrill, and pollution on drilling wells and a $2,000,000 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. Additionally, pollution and similar environmental risks generally are not fully insurable.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
President Obama’s Proposed Budget of the U.S. Government, Fiscal Year 2011, includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. In March 2010, the EPA announced a proposed rulemaking that would expand its final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production facilities. If the proposed rule is finalized in its current form, reporting of GHG emissions from such facilities would be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Federal and state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases. The EPA has already made findings and issued proposed regulations that could lead to the imposition of restrictions on greenhouse gas emissions from motor vehicles and certain stationary sources and that could require us to establish and report an inventory of greenhouse gas emissions. In addition, the U.S. Congress has been considering various bills that would establish an economy-wide cap-and-trade program to reduce U.S. emissions of
greenhouse gases, including carbon dioxide and methane. Such a program, if enacted, could require phased reductions in greenhouse gas emissions over several or many years as could the issuance of a declining number of tradable allowances to sources that emit greenhouse gases into the atmosphere. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.
Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.
The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which contains comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation contains significant derivatives regulation, including provisions requiring certain transactions to be cleared on exchanges and containing a requirement to post cash collateral (commonly referred to as “margin”) for such transactions as well as certain clearing and trade-execution requirements in connection with our derivative activities. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. However, we do not know the definitions that the CFTC will actually promulgate nor how these definitions will apply to us. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.
Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer counterparties for our commodities hedging transactions. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. In addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. In addition,
in March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Thus, even if the pending bills are not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the SDWA.
Risks Related to Our Business
Our auditors have issued a “going concern” audit opinion.
Our consolidated financial statements as of June 30, 2010 have been prepared on the assumption that we will continue as a going concern. Our independent accountants have issued a report dated September 22, 2010 stating that our significant losses from operations and net capital deficiency raise substantial doubt as to our ability to continue as a going concern. Investors in our securities should review carefully the report of Hein & Associates LLP. There can be no assurance that we will be able to continue as a going concern.
We have no borrowing capacity under our credit agreements, and unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.
We have sustained recurring losses and negative cash flows from operations. Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of equity financings, borrowings under our credit agreements, the sale of assets and cash flows from operating activities. As of June 30, 2010, we had approximately $0.3 million of cash and cash equivalents available to fund operations. See Note 2 to our Consolidated Financial Statements.
On July 20, 2010, we terminated our announced merger with Resaca that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009. On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives, with a goal of maximizing economic value for our shareholders. The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.
We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived covenant compliance issues for the period ended June 30, 2010 and potential covenant compliance issues for the period ending September 30, 2010, set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete our strategic alternatives process. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.
The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred and our current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. The ability of the Company to continue as a going concern will be dependent upon the outcome of the strategic alternatives review. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. We can provide no assurance that we will be successful in our efforts to execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital.
We are subject to potential early repayments as well as restrictions pursuant to the terms of our Series D Convertible Preferred Stock which may adversely impact our operations.
Pursuant to the terms of our Series D Convertible Preferred Stock (“the Preferred Stock”), if a “triggering event” occurs, the holders of our Preferred Stock will have the right to require us to redeem their Preferred Stock at a price of at least 125% of the $1,000 per share stated value of the Preferred Stock plus accrued dividends. “Triggering events” include the following:
· our common stock is suspended from trading or fails to be listed on the AMEX, the New York Stock Exchange,
the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market;
· we fail to convert and do not cure this failure within 10 business days after the conversion date or give notice of our intention not to comply with a request for conversion;
· we fail to pay for at least 5 business days any amount when due pursuant to the terms of the Preferred Stock or any documents related to the sale and registration rights of the Preferred Stock, common stock and warrants;
· we take certain actions, or third parties take certain actions, with regard to bankruptcy;
· we default on any indebtedness which default is not waived and the applicable grace period has expired; or
· we breach any representation, warranty, covenant or other term or condition of any document relating to the sale and registration rights relating to the Preferred Stock, the common stock and the warrants, which, to the extent such breach is curable, such breach is not cured within 7 business days.
There is no guarantee that we would be able to repay the amounts due under our Preferred Stock upon the occurrence of a “triggering event.”
In addition, we cannot issue any preferred stock that is senior or on par with the Preferred Stock with regard to dividends or liquidation without the approval of holders of a majority of the Preferred Stock.
If we file for bankruptcy protection, holders of our common stock and preferred stock may be severely diluted or eliminated entirely in connection with a bankruptcy filing or restructuring transaction.
If we are unable to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. As a result, we will likely file for bankruptcy or seek similar protection. Moreover, it is possible that our creditors may seek to initiate involuntary bankruptcy proceedings against us or against one or more of our subsidiaries, which would force us to make defensive voluntary filing(s) of our own. In addition, if we restructure our debt or file for bankruptcy protection, it is very likely that our common stock and preferred stock will be severely diluted if not eliminated entirely.
Our limited history makes an evaluation of us and our future difficult and profits are not assured.
In view of our limited history in the oil and natural gas business, you may have difficulty in evaluating us and our business and prospects. Since May 2004, we have acquired rights in oil and natural gas properties and undertaken certain exploitation activities. We are in the early stages of two waterfloods and one ASP project. You must consider our business and prospects in light of the risks, expenses and difficulties frequently encountered by companies similar to ourselves. Generally, for our business plan to succeed, we must successfully undertake the following activities:
· develop our oil and natural gas properties, including the successful application of EOR technologies, to the point at which oil and natural gas are being produced in commercially viable quantities;
· contract with third parties regarding services necessary to develop our oil and natural gas properties;
· contract with transporters and purchasers of our oil and natural gas production;
· maintain access to funds to pursue our capital-intensive business plan;
· comply with all applicable laws and regulations;
· implement and successfully execute our business strategy;
· find and acquire rights in strategic oil and natural gas properties;
· respond to competitive developments and market changes; and
· attract, retain and motivate qualified personnel.
There can be no assurance that we will be successful in undertaking such activities. Our failure to successfully undertake most of the activities described above could materially and adversely affect our business, prospects, financial
condition and results of operations. There can be no assurance that sales of our oil and natural gas production will be able to sustain profitability in any future period.
We are subject to many restrictions imposed by our lenders under our credit agreements and consent and forbearance agreements which may adversely impact our future operations.
We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived potential covenant compliance issues for the periods ending June 30, 2010 and September 30, 2010, set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete its strategic alternatives process. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.
If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.
Our business strategy includes developing and acquiring interests in mature oil fields with established primary and/or secondary reserves that may possess significant remaining upside exploitation potential by implementing various secondary and/or tertiary EOR techniques. As we continue our business plan, we may require additional capital to finance acquisitions as well as to conduct our EOR operations. Due to our current liquidity constraints, it is unlikely that we will make any acquisitions of oil and gas properties and related assets or entities owning such assets for the foreseeable future. Additionally, in the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implement our business strategy, we may be required to curtail operations or develop a different strategy, which could adversely affect our financial condition and results of operations. Further, any debt financing must be repaid and redeemable preferred stock must be redeemed regardless of whether or not we generate profits or cash flows from our business activities.
The actual quantities and present value of our proved reserves may be lower than we have estimated.
This annual report contains estimates of our proved reserves. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Approximately 80% of our total proved reserves as of June 30, 2010 consisted of undeveloped reserves, and those reserves may not ultimately be developed or produced.
Approximately 80% of our total proved reserves as of June 30, 2010 were undeveloped. While we plan to develop and produce all of our proved reserves, these reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, nor at the costs we have budgeted, or at all. As of June 30, 2010, estimated development costs for our PDNP and PUD reserves were approximately $7.0 million and $303.5 million, respectively, through 2019.
We may not achieve the production growth we anticipate from our properties or properties we acquire.
Our operational strategy is to implement waterflood and EOR techniques upon our existing properties. The performance of waterflood and EOR techniques is often difficult to predict and takes an extended period of time from first investment until actual production. Additionally, we may not achieve the anticipated production growth from properties we own or acquire in the future.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our historical growth has been due in part to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from waterflood and EOR techniques, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform reviews of acquired properties which we believe are generally consistent with industry practices. However, such reviews will not reveal all existing or potential
problems. In addition, these reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Additionally, we do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties located in onshore United States. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions.
Exploration and development drilling and the application of waterflooding and EOR techniques may not result in commercially productive reserves.
The new wells we drill or participate in, whether undertaken in primary drilling or utilizing waterflood or EOR techniques may not be productive and we may not recover all or any portion of our investment. The engineering data and other technologies we use do not allow us to know conclusively, prior to beginning a project, that crude oil or natural gas is present in the reservoir or that those reserves can be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to generate an economic return. Further, our drilling and other operations may be curtailed, delayed or canceled as a result of a variety of factors, including but not limited to:
· unexpected drilling conditions;
· title and permitting problems;
· pressure or irregularities in formations;
· equipment failures or accidents;
· volatility in crude oil and natural gas prices;
· adverse weather conditions; and
· increases in the costs of, or shortages or delays in the availability of, chemicals, drilling rigs and equipment.
Certain of our current development and exploration (waterflood or EOR techniques where no proved waterflood or EOR reserves have previously been recorded) activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all crude oil and natural gas activities, whether developmental or exploratory, involve these risks, exploratory activities involve greater risks of failure to find and produce commercial quantities of crude oil or natural gas.
The departure of key management and personnel could adversely affect our ability to run our business.
Our future success is dependent on the personal efforts, performance and abilities of key management, including S. Jeffrey Johnson, our Chairman and Chief Executive Officer; Benjamin Daitch, Senior Vice President and Chief Financial Officer; Michael J. Ricketts, Vice President and Principal Accounting Officer; and Phillip Feiner, Vice President, Corporate Secretary and General Counsel. All of these individuals are integral parts of our daily operations. We have employment agreements with each of them. We do not maintain any key life insurance policies for any of our executive officers or other personnel. The loss of any officer could significantly impact our business until adequate replacements can be identified and put in place.
As a result of our strategic alternatives process, we are operating with a reduced work force which may affect our ability to run our business. Additionally, we may not be able to hire qualified replacements for lost employees in the future.
We face strong competition from larger oil and natural gas companies.
Our competitors include large integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of these competitors are well-established companies with substantially larger operating staffs and greater capital resources than we have. These larger competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in the industry.
The geographic concentration of our oil and gas reserves may have a greater effect on our ability to sell oil and gas compared to larger, more geographically diverse companies and may make us more sensitive to price volatility.
All of our oil and gas reserves are located in Texas, New Mexico and Oklahoma. Since our reserves are not as diversified geographically as many of our larger, more geographically diverse competitors, our business could be more subject to local conditions than other, more diversified companies. Any regional events, including price fluctuations, natural disasters, oil and gas processing or transportation interruptions, and restrictive regulations, that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified. For example, if a hurricane strikes certain areas of the Texas Gulf Coast, the price received for our natural gas sales may be negatively impacted due to the temporary closure of natural gas pipelines or natural gas liquids processing plants in the region impacted by the hurricane.
Our business will depend on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas that we produce.
The marketability of our crude oil and natural gas production will depend in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of crude oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations, financial condition and prospects.
Our ability to use net operating loss carryovers to offset future taxable income may be limited.
Depending on the outcome of our strategic alternatives review as discussed in Note 2 of the Consolidated Financial Statements, our federal income tax net operating loss (“NOL”) carryforwards could be subject to the ownership change limitation provisions of the Internal Revenue Code. This will result in a limitation on the use of NOL carryforwards to a specified amount per year. The Company expects to be able to fully utilize these existing NOL carryforwards in future years. However, there can be no certainty that any of our NOL carryforwards will be utilized by us in the future.
If the waterflood project at the Cockrell Ranch Unit of the Panhandle Properties is not successful, the aggregate reserves of the Panhandle Properties would be significantly reduced or eliminated.
Cano is currently undertaking a waterflood project at the Cockrell Ranch Unit on 62 injection wells and 71 producing wells on 1,023 developed acres. Production has increased from roughly 10 BOEPD to over 100 BOEPD since the initial phase of the project was started in July 2007. A number of performance issues, caused by using prior injectors that were open-hole completed, has limited the rate of project response. Cano has embarked on an active isolation program to address these issues and retained a third-party engineering firm to perform simulation modeling. The modeling results have not been completed, as it has been postponed pending the final results of our strategic alternatives review. Once completed, it is believed that waterflood production growth will more closely track the analog East Schafer Ranch response profile. Under the analogous East Schafer Ranch profile, the Cockrell Ranch Unit production would increase from the current levels of 40 BOEPD to approximately 270 BOEPD or roughly 4 BOEPD per producing well within the next 18 to 24 months after completion. The Cockrell Ranch unit contains 301 MBOE of PDP reserves based on actual performance to date and 1,782
MBOE of remaining PUD reserves. Should the project response at the Cockrell Ranch not match the expectations for the PUD reserve profile, the reserves for this project area would be significantly reduced or eliminated. Moreover, a complete failure at the Cockrell Ranch Unit waterflood would impair the PUD reserve calculations for the properties immediately adjacent to the Cockrell Ranch, and could partially impair the remainder of the Panhandle Properties.
Derivative activities create a risk of potentially limiting the ability to realize profits when prices increase.
Pursuant to the terms of our credit agreements, we are required to maintain our existing commodity derivative contracts to mitigate the impact of a decline in crude oil and natural gas prices. These commodity derivative contracts could prevent us from realizing the full advantage of increases in crude oil or natural gas prices if the NYMEX crude oil and natural gas prices exceed the contract price ceiling. In addition, these transactions may expose us to the risk of financial loss if the counterparties to our derivative contracts fail to perform under the contracts. Also, increases in crude oil and natural gas prices negatively affect the fair value of our commodity derivatives contracts recorded on our balance sheet and, consequently, our reported net income. Changes in the recorded fair value of our derivatives contracts are marked to market through earnings and the decrease in the fair value of these contracts during any period could result in significant charges to earnings. We are currently unable to estimate the effects on earnings in future periods, but the effects could be significant.
Failure to maintain effective internal controls could have a material adverse effect on our operations.
We are subject to Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal control over financial reporting. 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, 2010, we concluded that we maintained effective internal control over financial reporting as of June 30, 2010, 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.
Part of our business is seasonal in nature which may affect the price of our oil and natural gas sales and severe weather may adversely impact our ability to deliver oil and natural gas production.
Weather conditions affect the demand for and price of oil and natural gas. Demand for oil and natural gas is typically higher during winter months than summer months. However, warm winters can also lead to downward price trends. Therefore, our results of operations may be adversely affected by seasonal conditions. Severe weather can cause interruptions to our production and temporarily shut-in production from our wells.
Unfavorable results of litigation could have a material adverse impact on our financial statements.
We are subject to a variety of claims and lawsuits that arise from time to time in the ordinary course of our business. Management currently believes that resolving any of such matters, individually or in the aggregate, will not have a material adverse impact on our financial position or results of operations. The litigation and claims are subject to inherent uncertainties and management’s view of these matters may change in the future. There exists the possibility of a material adverse impact on our financial position and the results of operations for the period in which the effect of an unfavorable final outcome becomes probable and reasonably estimable. Please see “Legal Proceedings” for a discussion of our material pending legal proceedings.
Currently, our lease operating expense per BOE is high in comparison to the oil and natural gas industry as a whole.
Until such time as we achieve significant production growth from our waterfloods, our lease operating expense per BOE should remain higher than companies drilling for primary production. These higher operating costs could have an adverse effect on our results of operations.
Risks Related to Our Common Stock
Failure to obtain a satisfactory result from our strategic alternatives process could adversely affect our common stock price, and our future business and financial results.
On July 20, 2010, following our termination of the Agreement and Plan of Merger with Resaca we announced the initiation of a strategic alternatives process designed to achieve the best available economic value for our shareholders. The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, or potential business combinations. We currently have a severe shortage of working capital and funds to pay our liabilities, and we currently have no available borrowing capacity under our senior or subordinated credit agreements. We were not in compliance with the interest coverage ratio and leverage ratio at June 30, 2010. On August 6, 2010, we finalized Forbearance Agreements with our lenders that set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for $0.8 million. The cash proceeds from the sale of the derivative contracts is expected to provide us sufficient liquidity to complete our strategic alternatives process. Our Consolidated Financial Statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the losses incurred and current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. The ability of Cano to continue as a
going concern is dependent upon the strategic alternatives process, as previously discussed. There can be no assurance that our strategic alternatives process will adequately resolve issues regarding our liquidity or going concern status.
Our historic stock price has been volatile and the future market price for our common stock may continue to be volatile. This may make it difficult for you to sell our common stock for a positive return on your investment.
The public market for our common stock has historically been very volatile. On September 16, 2010, our closing price on the NYSE Amex was $0.75. Any future market price for our shares may continue to be very volatile. The stock market in general has experienced extreme price and volume fluctuations that often are unrelated or disproportionate to the operating performance of companies. Broad market factors and the investing public’s negative perception of our business may reduce our stock price, regardless of our operating performance. Market fluctuations and volatility, as well as general economic, market and political conditions, could reduce our stock price. As a result, this may make it difficult or impossible for you to sell our common stock for a positive return on your investment.
If we fail to meet continued listing standards of NYSE Amex, our common stock may be delisted which would have a material adverse effect on the price of our common stock.
In order for our securities to be eligible for continued listing on NYSE Amex, we must remain in compliance with certain listing standards. Among other things, these standards require that we remain current in our filings with the SEC and comply with certain provisions of the Sarbanes-Oxley Act of 2002. If we were to become noncompliant with NYSE Amex’s continued listing requirements, our common stock may be delisted which would have a material adverse affect on the price of our common stock. This is also a “triggering event” under our Preferred Stock which could cause the holders of our Preferred Stock to have the right to require us to redeem their Preferred Stock at a price of at least 125% of the $1,000 per share stated value of the Preferred Stock plus accrued dividends.
If we are delisted from NYSE Amex, our common stock may become subject to the “penny stock” rules of the SEC, which would make transactions in our common stock cumbersome and may reduce the value of an investment in our stock.
The SEC has adopted Rule 3a51-1 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that is not listed on a national securities exchange or registered national securities association’s automated quotation system and has a market price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, Rule 15g-9 requires:
· that a broker or dealer approve a person’s account for transactions in penny stocks; and
· the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.
In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:
· obtain financial information and other information regarding the investment experience and objectives of the person; and
· make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.
The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:
· sets forth the basis on which the broker or dealer made the suitability determination; and
· confirms the broker or dealer received a signed, written agreement from the investor prior to the transaction.
Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.
If securities analysts downgrade our stock or cease coverage of us, the price of our stock could decline.
The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control the reports these analysts publish about us. Furthermore, there are many large, well-established, publicly-traded companies active in our industry and market, which may make it less likely that we
will receive widespread analyst coverage. If one or more of the analysts who do cover us downgraded our stock, our stock price would likely decline rapidly. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.
We do not pay dividends on our common stock.
We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business, including capital expenditures, and to retire debt. Any decisions to pay dividends on the common stock in the future will depend upon our profitability at the time, available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our credit agreements and our Preferred Stock.
Provisions in our corporate governance and loan documents, the terms of our Preferred Stock and Delaware law may delay or prevent an acquisition of Cano, which could decrease the value of our common stock.
Our certificate of incorporation, our Preferred Stock, our bylaws, our credit agreements and the Delaware General Corporation Law contain provisions that may discourage other persons from initiating a tender offer or takeover attempt that a stockholder might consider to be in the best interest of all stockholders, including takeover attempts that might result in a premium to be paid over the market price of our stock.
The terms of our Preferred Stock give its holders the right to have their Preferred Stock redeemed upon a “change of control.” In addition, the terms of our Preferred Stock do not permit us to enter into certain transactions that would constitute a “change of control” unless the successor entity assumes all of our obligations relating to the Preferred Stock and the holders of a majority of our Preferred Stock approve such assumption and the successor entity is publicly-traded on the NYSE Amex, the New York Stock Exchange, the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market.
In addition, subject to the terms of the Preferred Stock, we are authorized to issue additional shares of preferred stock. Subject to the terms of the Preferred Stock and our certificate of incorporation, our board of directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the board of directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:
· restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;
· dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;
· dilution of the equity interest of common stock and other series of preferred stock; and
· limitation on the right of holders of common stock and other series of preferred stock to share in Cano’s assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.
The terms of our Preferred Stock and the provisions in our corporate governance documents regarding the granting of additional preferred stock may deter or render more difficult proposals to acquire control of our company, including proposals a stockholder might consider to be in his or her best interest, impede or lengthen a change in membership of our Board of Directors and make removal of our management more difficult. Furthermore, Delaware law imposes some restrictions on mergers and other business combinations between our company and owners of 15% or more of our common stock. These provisions apply even if an acquisition proposal is considered beneficial by some stockholders and therefore could depress the value of our common stock.
The conversion price of our Preferred Stock may be lowered if we issue shares of our common stock at a price less than the existing conversion price which could cause further dilution to our common stockholders.
Subject to certain exclusions, if we issue common stock at a price less than the existing conversion price for our Preferred Stock, the conversion price shall be adjusted downward which would further dilute our common stock holders upon conversion.
Our Preferred Stock has voting rights both together with and separate from our common stock which could adversely affect our common stockholders.
The holders of our Preferred Stock vote together with the holders of our common stock on an as-converted basis, subject to a limitation on how many votes the Series D Convertible Preferred Stock holders may cast if the conversion price falls below $4.79. In addition, approval of holders of a majority of the Series D Convertible Preferred Stock is required for us to take the following actions:
· to modify the certificate of incorporation or bylaws in a manner adverse to the Preferred Stock;
· increase or decrease the number of authorized shares of Preferred Stock;
· create any class of preferred stock that has a preference over or is in parity with the Preferred Stock with respect to dividends or liquidation;
· purchase, repurchase or redeem any share of common stock;
· pay dividends or make any other distribution on the common stock; or
· circumvent a right of the Preferred Stock.
These voting rights may have an adverse impact on the common stock and the voting power of our common stockholders.
Since we are a United States real property holding corporation, non-U.S. investors may be subject to U.S. federal income tax (including withholding tax) on gains realized on disposition of our shares, and U.S. investors selling our shares may be required to certify as to their status in order to avoid withholding.
Since we are a United States real property holding corporation, a non-U.S. holder of our common stock will generally be subject to U.S. federal income tax on gains realized on a sale or other disposition of our common stock. Certain non-U.S. holders of our common stock may be eligible for an exception to the foregoing general rule if our common stock is regularly traded on an established securities market during the calendar year in which the sale or disposition occurs. However, we cannot offer any assurance that our common stock will be so traded in the future.
If our common stock is not considered to be regularly traded on an established securities market during the calendar year in which a sale or disposition occurs, the buyer or other transferee of our common stock will generally be required to withhold tax at the rate of 10% of the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable Treasury regulations.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
See “Items 1 and 2. Business and Properties.”
Item 3.
Item 3. Legal Proceedings.
Burnett Case
On March 23, 2006, the following lawsuit was filed in the 100th Judicial District Court in Carson County, Texas: Cause No. 9840, The Tom L. and Anne Burnett Trust, by Anne Burnett Windfohr, Windi Phillips, Ben Fortson, Jr., George Beggs, III and Ed Hudson, Jr. as Co-Trustees; Anne Burnett Windfohr; and Burnett Ranches, Ltd. v. Cano Petroleum, Inc.,
W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and natural gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas.
The plaintiffs (i) allege negligence and gross negligence and (ii) seek damages, including, but not limited to, damages for damage to their land and livestock, certain expenses related to fighting the fire and certain remedial expenses totaling approximately $1.7 million to $1.8 million. In addition, the plaintiffs seek (i) termination of certain oil and natural gas leases, (ii) reimbursement for their attorney’s fees (in the amount of at least $549,000) and (iii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The owner of the remainder of the mineral estate, Texas Christian University, intervened in the suit on August 18, 2006, joining Plaintiffs’ request to terminate certain oil and gas leases. On June 21, 2007, the judge of the 100th Judicial District Court issued a Final Judgment (a) granting motions for summary judgment in favor of Cano and certain of its subsidiaries on plaintiffs’ claims for (i) breach of contract/termination of an oil and gas lease; and (ii) negligence; and (b) granting the plaintiffs’ no-evidence motion for summary judgment on contributory negligence, assumption of risk, repudiation and estoppel affirmative defenses asserted by Cano and certain of its subsidiaries.
The Final Judgment was appealed and a decision was reached on March 11, 2009, as the Court of Appeals for the Tenth District of Texas in Amarillo affirmed in part and reversed in part the ruling of the 100th Judicial District Court. The Court of Appeals (a) affirmed the trial court’s granting of summary judgment in Cano’s favor for breach of contract/termination of an oil and gas lease and (b) reversed the trial court’s granting of summary judgment in Cano’s favor on plaintiffs’ claims of Cano’s negligence. The Court of Appeals ordered the case remanded to the 100th Judicial District Court. On March 30, 2009, the plaintiffs filed a motion for rehearing with the Court of Appeals and requested a rehearing on the affirmance of the trial court’s holding on the plaintiffs’ breach of contract/termination of an oil and gas lease claim. On June 30, 2009, the Court of Appeals ruled to deny the plaintiff’s motion for rehearing. On August 17, 2009 we filed an appeal with the Texas Supreme Court to request the reversal of the Court of Appeals ruling regarding our potential negligence. On December 11, 2009, the Texas Supreme Court declined to hear Cano’s appeal. Therefore, this case has been remanded to the district court for trial on the negligence claims and the trial date has been set for November 2, 2010.
Due to the inherent risk of litigation, the ultimate outcome of this case is uncertain and unpredictable. At this time, Cano management continues to believe that this lawsuit is without merit and will continue to vigorously defend itself and its subsidiaries, while seeking cost-effective solutions to resolve this lawsuit. Based on our knowledge and judgment of the facts as of September 22, 2010, we believe our financial statements present fairly the effect of the actual and the anticipated future costs to resolve this matter as of June 30, 2010.
There is no remaining insurance coverage for any claims associated with this fire litigation.
Securities Litigation against Outside Directors
On October 2, 2008, a lawsuit (08 CV 8462) was filed in the United States District Court for the Southern District of New York, against David W. Wehlmann; Gerald W. Haddock; Randall Boyd; Donald W. Niemiec; Robert L. Gaudin; William O. Powell, III and the underwriters of the June 26, 2008 public offering of Cano common stock (“Secondary Offering”) alleging violations of the federal securities laws. Messrs. Wehlmann, Haddock, Boyd, Niemiec, Gaudin and Powell were Cano outside directors on June 26, 2008. At the defendants’ request, the case was transferred to the United States District Court for the Northern District of Texas.
On July 2, 2009, the plaintiffs filed an amended complaint that added as defendants Cano, Cano’s Chief Executive Officer and Chairman of the Board, Jeff Johnson, Cano’s former Senior Vice President and Chief Financial Officer, Morris B. “Sam” Smith, Cano’s current Senior Vice President and Chief Financial Officer, Ben Daitch, Cano’s Vice President and Principal Accounting Officer, Michael Ricketts and Cano’s former Senior Vice President of Engineering and Operations, Patrick McKinney, and dismissed Gerald W. Haddock, a former director of Cano, as a defendant. The amended complaint alleges that the prospectus for the Secondary Offering contained statements regarding Cano’s proved reserve amounts and standards that were materially false and overstated Cano’s proved reserves. The plaintiff is seeking to certify the lawsuit as a class action lawsuit and is seeking an unspecified amount of damages. On July 27, 2009, the defendants moved to dismiss the lawsuit. On December 3, 2009, the U.S. District Court for the Northern District of Texas granted motions to dismiss all claims brought by the plaintiffs. On December 18, 2009, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On April 5, 2010, Cano filed its appellate brief to support its position. On April 19, 2010, the plaintiffs filed their response brief. On August 4, 2010, the U.S. Court of Appeals for the Fifth Circuit affirmed the dismissal by the U.S. District Court for the Northern District of Texas of all claims by the plaintiffs. By affirming the decision of the lower court, the U.S. Court of Appeals for the Fifth Circuit agreed that the plaintiff’s complaint failed to state a claim upon which
relief could be granted, and thus found merit in dismissing the lawsuit. Due to the inherent risk of litigation, the outcome of this lawsuit is uncertain and unpredictable; however, Cano, its officers and its outside directors intend to continue to vigorously defend the lawsuit.
Cano is cooperating with its directors and officers liability insurance carrier regarding the defense of the lawsuit. We believe that the potential amount of losses resulting from this lawsuit in the future, if any, will not exceed the policy limits of Cano’s directors’ and officers’ liability insurance.
Other
Occasionally, we are involved in other various claims and lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management does not believe that the ultimate resolution of any current matters that are not set forth above will have a material effect on our financial position or results of operations. Management’s position is supported, in part, by the existence of insurance coverage, indemnification and escrow accounts. None of our directors, officers or affiliates, owners of record or beneficial owners of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.
Section 7.6 of the Merger Agreement with Resaca provided for the Company and Resaca to share transaction expenses related to the printing, filing and mailing of the registration statement, the proxy/prospectus, and the solicitation of stockholder approvals. On September 2, 2010, we filed an action against Resaca in the Tarrant County District Court seeking a declaratory judgment to clarify the scope and determine the amount of any expenses that are reimbursable under Section 7.6 of the Merger Agreement.
Environmental
To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Item 4.
Item 4. (Removed and Reserved).
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our shares of common stock are listed on the NYSE Amex under the trading symbol “CFW.” For the years ended June 30, 2009 and 2010, the following table sets forth the high and low sales prices per share of common stock for each quarterly period. On September 16, 2010, the closing sale price of our common stock on the NYSE Amex was $0.75.
Holders
As of September 16, 2010, our shares of common stock were held by approximately 106 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 16, 2010, there were approximately 7,300 beneficial holders who own shares of our common stock in street name.
Dividends
We have not declared any dividends to date on our common stock. We have no present intention of paying any cash dividends on our common stock in the foreseeable future, as we intend to reinvest earnings, if any, into our operations. Our
credit agreements do not permit us to pay dividends on our common stock. In addition, the terms of our Preferred Stock do not permit us to pay dividends on our common stock without the approval of the holders of a majority of the Preferred Stock.
For the year ended June 30, 2010, the Preferred Stock dividend was $1.8 million, of which $1.1 million were paid-in-kind dividends. On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.
During the year ended June 30, 2010, there were no equity securities issued pursuant to transactions exempt from 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.
ISSUER PURCHASES OF EQUITY SECURITIES
(1) Shares of our common stock were delivered to us during the fourth quarter of 2010 to satisfy tax withholding obligations by S. Jeffrey Johnson, Benjamin Daitch, Patrick McKinney, Michael J. Ricketts and Phillip Feiner pursuant to the terms of the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan to satisfy tax withholding obligations related to the vesting of their respective restricted stock awards. In addition, Mr. McKinney forfeited 78,334 restricted common shares of Cano stock upon his resignation on May 31, 2010.
Item 6.
Item 6. Selected Financial Data.
Not applicable.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain of the matters discussed under the captions “Business and Properties,” “Legal Proceedings,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this annual report may constitute “forward-looking” statements for purposes of the Securities Act of 1933, and the Securities Exchange Act of 1934 and, as such, may involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. When used in this report, the words “anticipates,” “estimates,” “plans,” “believes,” “continues,” “expects,” “projections,” “forecasts,” “intends,” “may,” “might,” “could,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. Various factors could cause the actual results, performance or achievements to differ materially from our expectations. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements disclosed in this annual report (“Cautionary Statements”), including, without limitation, those statements made in conjunction with the forward-looking statements included under the captions identified above and otherwise herein. All written and oral forward-looking statements attributable to us are qualified in their entirety by the Cautionary Statements. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law and you are cautioned not to place undue reliance on any forward-looking statement.
Overview
Introduction
We are an independent oil and natural gas company. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery at a low cost. We intend to convert our proved undeveloped and/or unproved reserves into proved producing reserves by applying water, gas and/or chemical flooding and other EOR techniques. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma.
During our first three years of operations, our primary objective was to achieve growth through acquiring existing, mature crude oil and natural gas fields. Since then, we have focused on waterflood operations in our two largest properties, Panhandle and Cato. These development activities are more clearly described below under “-Drilling Capital Development and Operating Activities Update.”
As discussed under “-Liquidity / Going Concern,” on July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009. On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives. The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.
Proved Reserves
On September 14, 2010, we announced the results of our year-year reserves review as of June 30, 2010 as prepared by Haas, our independent petroleum engineer. The following table compares our proved reserves by property as of June 30, 2010 to June 30, 2009. The amounts are presented in thousands of barrels oil equivalent (“MBOE”).
(in MBOE)
As of June 30, 2010, our proved reserves total 42.5 MMBOE, or 6.6 MMBOE lower than our proved reserves of 49.1 MMBOE at June 30, 2009. The primary contributors to the 6.6 MMBOE decrease are reduced PUD reserves at the Panhandle Properties of 4.4 MMBOE, reduced PDP reserves at the Cato Properties of 0.9 MMBOE, the sale of certain wells in the Panhandle Properties of 0.5 MMBOE (as discussed in Note 7 to our Consolidated Financial Statements) and production for the twelve-month period ended June 30, 2010 of 0.4 MMBOE.
Haas utilized the East Schafer Ranch waterflood as the analogy for assessing the PUD reserves for each lease of the Panhandle Properties. The East Shafer Ranch waterflood experienced a secondary recovery of 11% of the original oil in place, or OOIP, which equated to a secondary to primary ratio of 0.35. Haas, based solely on its professional experience and engineering judgment, determined that for the purpose of reporting the Panhandle Properties’ proved reserves, they would limit each of the Panhandle Properties’ waterflood recovery factors to a 0.35 secondary to primary ratio as a maximum, and not use a percentage of OOIP to determine proved reserves. In some cases, adjustments were made since the by lease production history appeared to have allocation issues. Haas’ decision to limit proved reserve recovery based upon a 0.35 secondary to primary ratio resulted in a proved reserve decrease of 3.1 MMBOE. Further, Haas looked at the delayed responses Cano has experienced at its Cockrell Ranch unit, along with reservoir conformance and permeability trends analyzed from core data, and decided to limit proved reserves to a 0.175 secondary to primary ratio for the Cockrell Ranch and the adjacent Pond Lease, resulting in a proved reserve decrease of 1.3 MMBOE. Haas determined that the reductions to the combined company’s proved reserves would be validly reclassified as probable reserves as proved reserves indicate a 90% likelihood that production will meet or exceed the booked value while probable reserves require a 50% confidence level to be so classified.
The reduction of PDP reserves at Cato Properties is a result of lower field production rates associated with lower water injection rates at the waterflood.
The reserve estimates as of June 30, 2010 include the effects of the SEC’s final rule, Modernization of Oil and Gas Reporting, issued in December 2008. This final rule is effective for annual reports on Form 10-K for years ending on or after December 31, 2009.
The prices used to compute the crude oil and natural gas proved reserves represent the unweighted average first-day-of-the-month NYMEX crude oil and natural prices for the past 12 fiscal months ended June 30, 2010, pursuant to the previously discussed SEC’s final rule, which we compute to be $75.76 per barrel and $4.10 per MMBtu, respectively, as compared to $68.89 per barrel and $3.71 per MMBtu on June 30, 2009. Crude oil reserves accounted for 78% of our total proved reserves at June 30, 2010.
The table below summarizes the changes in our proved reserves from June 30, 2009 to June 30, 2010.
Extensions and Discoveries totaling 279 MBOE include newly identified behind-pipe opportunities at our Cato and Panhandle Properties. Additionally, approximately 60 MBOE of previously categorized PDNP reserves at the Desdemona Properties were reclassified to PDP reserves as we are in the midst of a development project to return to production previously shut-in gas wells from the Duke Sand formation. Our development activities are more fully described below under “-Development Capital Expenditures and Operating Activities Update.”
Drilling Capital Development and Operating Activities Update
For the quarter ending June 30, 2010 (“current quarter”) our production averaged 1,149 net barrels of oil equivalent per day (BOEPD), which was 52 BOEPD (4.3%) lower as compared to production of 1,201 BOEPD for the quarter ended June 30, 2009 (“prior year quarter”). Production for the year ended June 30, 2010 (“2010 Fiscal Year”) of 1,102 net BOEPD was 42 BOEPD (3.7%) lower as compared to the year ended June 30, 2009 (“2009 Fiscal Year”) of 1,144 net BOEPD. These reported production amounts exclude the sale of Certain Panhandle Properties, as discussed in Note 7 to the Consolidated Financial Statements, which averaged 98 BOEPD during the 2010 Fiscal Year. For both the current quarter and 2010 Fiscal Year, the production decreases were primarily attributed to mandatory lower waterflood injection volumes at our Cato Properties, as discussed below. At our other properties, normal field declines of production were offset by workover activities and return-to-production (“RTP”) program at the Desdemona Field.
For the 2010 Fiscal Year, we incurred development capital expenditures of $12.2 million (excludes capitalized general and administrative and interest expenses). Our development capital budget was designed to maintain our current level of production and to minimize drawing on the ARCA while we pursued the completion of the planned merger with Resaca. The development capital expenditures were incurred as follows:
· $4.5 million at the Cato Properties,
· $6.9 million at the Panhandle Properties, and
· $0.8 million at the Desdemona Properties.
The following is a discussion of our field level activity during the 2010 Fiscal Year.
Cato Properties.
Our 2010 Fiscal Year development capital plan included expanding the waterflood footprint from 640 acres to approximately 1,000 acres by adding three new injection wells, which were put into service during the quarter ended December 31, 2009. We have identified a new source of water in a non-productive formation within our acreage, and have
confirmed that the water well is capable of producing 2,500 to 3,000 barrels of water per day. This new water source formation has been penetrated in a number of existing wellbores in the Cato Properties and confirms the reservoir continuity necessary to validate it as a reliable water source for future expansion of the Cato waterflood. As we develop this new water source, we will be able to increase the waterflood footprint without decreasing the injection rate at our existing injectors, which should enable us to maintain production from existing producing wells at current levels. We averaged 14,000 barrels of water injection per day (“BWIPD”) during the quarter ended September 30, 2009. We experienced a decrease to 12,000 BWIPD through March 31, 2010, as we measured increasing injection pressures in the northern part of the flood area and we were required, under our existing waterflood permit, to reduce the injection rate in these wells. On May 6, 2010, we received administrative approval from the New Mexico Oil and Gas Conservation Division (“NMOGCD”) to increase injection pressures at the 14 active wells to our current physical plant capabilities of approximately 21,000 BWIPD. As of August 31, 2010, we have maintained an injection rate of 12,000 BWIPD, which is less than the approved rate from the NMOGCD as we have reduced capital spending pending the outcome of our strategic alternatives review. We have seen increased fluid production rates and corresponding increasing crude oil rates from this waterflood. We have submitted an application to the NMOGCD to expand the waterflood operations and expect their approval by December 2010.
The Cato Properties will be developed through the purchase of additional equipment to increase water injection and to increase fluid production and crude oil rates from this waterflood. Additional development plans for the Cato Properties include behind-pipe recompletions, restoration of production from the Tom-Tom and Tomahawk fields, and the drilling of a Morrow formation test well. Net production at the Cato Properties for the quarter ended June 30, 2010 was 237 BOEPD, which was 96 BOEPD lower than the prior year quarter of 333 BOEPD. Net production at the Cato Properties for the 2010 Fiscal Year was 257 BOEPD, which was 39 BOEPD lower than 2009 Fiscal Year of 296 BOEPD. The decreases for the current quarter and 2010 Fiscal Year resulted from the reduction in injected water and redistribution of water injection at the waterflood.
Please see “Business Properties - Our Properties - Cato Properties” for a description of the Cato Properties.
Panhandle Properties.
In the quarter ended September 30, 2009, we established a controlled water injection pattern at the Cockrell Ranch unit to gauge the effects of optimizing water injection into the highest remaining crude oil saturation intervals of the Brown Dolomite formation. We essentially performed a “Mini-Flood” in the key target interval at the Cockrell Ranch unit. The result of this field observation helped us determine an optimal pattern for waterflooding the balance of the Cockrell Ranch unit with an increasingly predicable production profile. Moreover, the field observation should improve the planning of future development programs for the remaining leases located within our Panhandle Properties. To isolate the observed wells, we had temporarily shut-in production during most of the quarter ended September 30, 2009, which reduced Panhandle production by 25 net BOEPD. All production that was shut-in for the controlled injection project was restored on September 28, 2009. We have experienced positive results from the controlled injection project. Oil production from wells in the affected area has increased to at or above target levels of 8-12 BOEPD on a per well basis.
Net production at the Panhandle Properties, as adjusted for the sale of Certain Panhandle Properties as discussed in Note 7 to the Consolidated Financial Statements, for the quarters ended June 30, 2010 and 2009 were 546 BOEPD and 517 BOEPD, respectively. Net production for the Panhandle Properties for the 2010 and 2009 Fiscal Years was 494 BOEPD and 495 BOEPD, respectively. During the 2010 Fiscal Year, we constructed gathering lines to redirect natural gas production from Eagle Rock Field Services L.P. (“Eagle Rock”) to DCP Midstream, LP (“DCP”). As of June 30, 2010, we had redirected approximately 80% of the natural gas production previously delivered to Eagle Rock to DCP.
Please see “Business Properties - Our Properties - Panhandle Properties” for a description of the Panhandle Properties.
Desdemona Properties.
During the 2010 Fiscal Year, we implemented a project to return to production previously shut-in gas wells from the Duke Sand formation. We converted approximately 311 MBOE of previously PDNP reserves to PDP reserves for 12 RTP’d gas wells in December 2009. Production increased from 46 BOEPD for the quarter ended December 31, 2009 to 69 BOEPD for the quarter ended March 31, 2010 without the benefit of selling any natural gas liquids (“NGLs”). We RTP’d an additional 13 wells during the quarter ended June 30, 2010. Production from all of the RTP’d natural gas wells, including associated NGL recovery from our gas plant, is expected to be approximately 10-20 Mcfe per day for each gas well returned to production. We have re-equipped our gas plant to handle the increased natural gas production and the gas plant became functional during August 2010. Daily production from the Desdemona Properties is projected to be 100 - 110 BOEPD.
During the quarter ended March 31, 2010, we drilled one new well to a total depth of 3,650 feet to test the Marble Falls, Atoka and Strawn Sand formations. We have completed the new well in the Strawn Sand formation at a depth of 1,750 feet. As of August 31, 2010, the well produced 5 BOEPD. We are currently evaluating this well to optimize production.
Net production at the Desdemona Properties for the quarters ended June 30, 2010 and June 30, 2009 was 69 BOEPD and 59 BOEPD, respectively. Net production at the Desdemona Properties for the 2010 and 2009 Fiscal Years was 55 BOEPD and 61 BOEPD, respectively. During July 2009, we shut-in our Barnett Shale natural gas wells based upon the then current and the outlook for natural gas prices from the Barnett Shale wells.
Please see “Business Properties - Our Properties - Desdemona Properties” for a description of the Desdemona Properties.
Nowata Properties. Proved reserves as of June 30, 2010 attributable to the Nowata Properties were 1.9 MMBOE, of which 1.8 MMBOE were PDP and 0.1 MMBOE were PDNP. Net production for the quarters ended June 30, 2010 and June 30, 2009 was 219 BOEPD and 218 BOEPD, respectively. Net production for the 2010 and 2009 Fiscal Years was 219 BOEPD and 221 BOEPD, respectively. We are currently assessing our operations at the Nowata Properties to increase production, including constructing an additional gas gathering system and optimizing current infrastructure. Please see “Business Properties - Our Properties - Nowata Properties” for a description of the Nowata Properties.
Davenport Properties. Proved reserves as of June 30, 2010 attributable to the Davenport Properties were 1.2 MMBOE, of which 0.7 MMBOE were PDP and 0.5 MMBOE were PDNP. Net production for the quarters ended June 30, 2010 and June 30, 2009 was 79 BOEPD and 74 BOEPD, respectively. Net production for the 2010 and 2009 Fiscal Years was 76 BOEPD and 71 BOEPD, respectively. Please see “Business Properties - Our Properties - Davenport Properties” for a description of the Davenport Properties.
Industry Conditions
We operate in a competitive environment for (i) acquiring properties, (ii) marketing oil and natural gas and (iii) attracting trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. Some of our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and obtain capital for investment in the oil and natural gas industry.
EOR techniques involve significant capital investment and an extended period of time, generally a year or longer, until production increases. Generally, surfactant-polymer injection is regarded as more risky as compared to waterflood operations. Our ability to successfully convert PUD reserves to PDP reserves will be contingent upon our ability to obtain future financing and/or raise additional capital. Further, there are inherent uncertainties associated with the production of crude oil and natural gas, as well as price volatility. See “Item 1A.Risk Factors.”
Liquidity and Capital Resources
Liquidity / Going Concern
At June 30, 2010, we had cash and cash equivalents of $0.3 million. We had negative working capital of $66.9 million, which includes $66.5 million of long-term debt that was shown as a current liability. For the year ended June 30, 2010, we had cash flow used in operations of $0.2 million, which included $1.9 million of merger-related cash expenses.
On July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009. On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives, with a goal of maximizing economic value for our shareholders. The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.
We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived potential covenant compliance issues for the periods ending June 30, 2010 and September 30, 2010, set certain deadlines for the execution of our strategic alternatives review and allowed us
to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete its strategic alternatives review. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.
The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred and our current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. The ability of the Company to continue as a going concern will be dependent upon the outcome of the strategic alternatives review. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.
On December 28, 2007, our universal shelf registration statement was declared effective by the SEC for the issuance of common stock, preferred stock, warrants, senior debt and subordinated debt up to an aggregate amount of $150.0 million. After the issuance of common stock on July 1, 2008, we have $96.0 million of availability under this registration; however, the amount of securities which we may offer pursuant to this shelf registration statement during any twelve-month period shall be limited to one-third of the aggregate market value of the common equity of the Company held by our non-affiliates since our public float is not in excess of $75.0 million. We may periodically offer one or more of these securities in amounts, prices and on terms to be announced when and if the securities are offered. At the time any of the securities covered by the registration statement are offered for sale, a prospectus supplement will be prepared and filed with the SEC containing specific information about the terms of any such offering. The universal shelf registration statement expires on December 31, 2010.
Credit Agreements
At June 30, 2010 and 2009, the outstanding amount due under our credit agreements was $66.5 million and $55.7 million, respectively. The $66.5 million at June 30, 2010, consisted of outstanding borrowings under the amended and restated credit agreement (the “ARCA”) and subordinated credit agreement (the “SCA”) of $51.5 million and $15.0 million, respectively. At June 30, 2010, the average interest rates under the ARCA and SCA were 2.85% and 6.54%, respectively.
Forbearance Agreements
On August 5, 2010, we executed a Consent and Forbearance Agreement (the “Senior Forbearance Agreement”) with Natixis and Union Bank, N.A. (“UBNA”), relating to existing and potential defaults under the ARCA dated December 17, 2008 among Cano, Natixis and UBNA and a Consent and Forbearance Agreement (together with the Senior Forbearance Agreement, the “Forbearance Agreements”) with UnionBanCal Equities, Inc. (“UBE”), relating to existing defaults under the SCA dated December 17, 2008 between Cano and UBE (as amended, the SCA and together with the ARCA, the “Credit Agreements”). Pursuant to the Forbearance Agreements, Natixis, UBNA and UBE agreed to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of the following defaults (the “Designated Defaults”):
· Cano’s failure to pay the amendment fees required by Amendment No. 2 to each of the Credit Agreements;
· Cano’s failure to provide an Internal Engineering Report and accompanying officer’s certificate on or before March 30, 2010, as required by the Credit Agreements;
· Cano’s potentially prohibited cash payments with respect to its shares of Preferred Stock on June 29, 2010 and June 30, 2010; and
· Cano’s failure to comply with certain financial covenants contained in the Credit Agreements for the quarter ended June 30, 2010 and potential failure to comply with such covenants for the quarter ended September 30, 2010.
The Forbearance Agreements also contain the following material terms:
· Natixis, UBNA and UBE consent to Cano’s termination of certain natural gas hedge contracts.
· Cano may not make any indirect or direct cash payment, cash dividend or cash distribution in respect of its shares of Preferred Stock.
· Natixis, UBNA and UBE agree to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of Cano’s potential failure to pay interest upon receipt of a default notice on the unpaid principal amount of each advance under the SCA on September 30, 2010.
· Cano must establish, on or before August 10, 2010, an electronic data room with information available to persons that may be interested in consummating an asset purchase, merger, combination, refinancing, recapitalization or other similar transaction with Cano (each, a “Prospective Transaction”).
· Cano must execute, on or before September 15, 2010, a letter of intent evidencing the parties’ intent to consummate a Prospective Transaction that will close on or before October 29, 2010 (the “Definitive Transaction”).
· Cano must execute definitive documentation providing for a Definitive Transaction on or before September 30, 2010.
· Cano must close a Definitive Transaction on or before October 29, 2010.
· Cano must deliver to UBNA and UBE a weekly written report of the parties visiting the electronic data room and a summary of progress and correspondence with respect to any Prospective Transaction.
· Cano must pay a forbearance fee in an amount equal to 1% of the aggregate principal amount of the advances outstanding under the Credit Agreements as of August 5, 2010 and the amendment fees required by Amendment No. 2 to each of the Credit Agreements upon receipt of proceeds from a Definitive Transaction.
· The aggregate commitments of Natixis and UBNA to lend to Cano pursuant to the ARCA are permanently reduced to $51.5 million, the current amount outstanding.
· UBNA and UBE shall not redetermine Cano’s borrowing bases under the Credit Agreements at any time prior to the termination of the Forbearance Agreements.
The Forbearance Agreements will terminate on the earlier of October 29, 2010, the date of Cano’s failure to comply with any of the terms described above and the date of the occurrence or existence of any default under either Credit Agreement, other than the Designated Defaults.
Regarding our compliance with the material items of the Forbearance Agreements:
· Prior to August 10, 2010, we did establish an electronic data room with information available to persons interested in consummating a Proposed Transaction.
· On August 10, 2010, we sold certain natural gas commodity derivative contracts to our counterparty, UBNA, for $0.8 million.
· At September 15, 2010, we were in discussions with parties regarding potential transaction structures and did not deliver a letter of intent pursuant to the Forbearance Agreements as discussed above. We continue to work with potential parties and our lenders on transaction structures.
The ARCA and SCA are discussed in greater detail below.
ARCA
On December 17, 2008, we finalized a new $120.0 million Amended and Restated Credit Agreement (the “ARCA”) with UBNA and Natixis. UBNA is the Administrative Agent and Issuing Lender of the ARCA. The current amount outstanding under the ARCA is equal to the commitment of $51.5 million. Per the terms of the Forbearance Agreement, the ARCA’s borrowing base shall not be redetermined.
Based upon the terms of the Forbearance Agreement, our interest rate is the sum of the one, two or three month LIBOR rate and 2.75%. As of the Forbearance Agreement, there will not be a commitment fee and we are deemed fully borrowed.
Unless specific events of default occur, the maturity date of the ARCA is December 17, 2012. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. The ARCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBNA, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBNA, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.
SCA
On December 17, 2008, we finalized a $25.0 million SCA among Cano and UBE, as the Administrative Agent. On March 17, 2009, we borrowed the maximum available amount of $15.0 million under this agreement.
The interest rate is the sum of (a) the one, two or three month LIBOR rate (at our option) and (b) 6.0%. Through March 17, 2009, we owed a commitment fee of 1.0% on the unborrowed portion of the available borrowing amount. We no longer have a commitment fee since we borrowed the full $15.0 million available amount.
Unless specific events of default occur, the maturity date is June 17, 2013. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change as defined in the SCA. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern. The SCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests of Cano; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBE, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBE, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.
Credit Agreement Covenant Compliance
Both the ARCA and the SCA have a current ratio covenant that requires us to maintain a ratio of not less than 1.00 to 1.00 for each fiscal quarter. The current ratio is calculated by dividing current assets (as defined in both credit agreements) by current liabilities (as defined in both credit agreements). Current assets include unused borrowing base under the ARCA and the aggregate availability under the SCA. Current liabilities exclude all current portions of long-term debt other than any current debt relating to the Preferred Stock and liabilities for asset retirement obligations. Current assets and current liabilities exclude derivative assets and liabilities. At June 30, 2010, our ratio of current assets to current liabilities was 1.89 to 1.00. The calculation and reconciliation of current assets and current liabilities, as defined by GAAP, to current assets and current liabilities, as defined in the credit agreements is as follows (in thousands):
(1) Represents the $60.0 million borrowing base under the ARCA at June 30, 2010, less $51.5 million of debt outstanding under the ARCA at June 30, 2010.
We were not in compliance with the covenants relating to our leverage ratio and interest coverage ratio for the quarters ended December 31, 2009, March 31, 2010 and June 30, 2010. The leverage ratio is the ratio of consolidated Debt (as defined in both credit agreements) to consolidated EBITDA (as defined in both credit agreements) for the cumulative four fiscal quarter periods. Under the ARCA and SCA, the leverage ratio cannot be greater than 4.00 to 1.00 and 4.50 to 1.00, respectively. The interest coverage ratio is the ratio of consolidated EBITDA (as defined in both credit agreements) to consolidated Interest Expense (as defined in both agreements) for the cumulative four fiscal quarter periods. Under the ARCA and SCA, the interest coverage ratio cannot be less than 3.00 to 1.00 and 2.50 to 1.00, respectively. The Forbearance Agreements address our non-compliance with the leverage ratio and interest coverage ratio, as previously discussed.
The SCA has a minimum asset coverage ratio covenant that requires us to maintain a ratio of not less than 1.50 to 1.00. The minimum asset coverage ratio is calculated by dividing (i) Total Present Value as of the applicable determination date, which is defined as the sum of 100% of the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to (A) PDP reserves, (B) PDNP reserves and (C) PUD reserves, with the total present value of PDP reserves being at least 60% of the aggregate total present value, by (ii) consolidated Debt (as defined in the Subordinated Credit Agreement) as of the applicable determination date. At June 30, 2010, our minimum asset coverage ratio was 2.03 to 1.00, calculated as follows (in thousands):
Results of Operations-Years Ended June 30, 2010, 2009 and 2008
Overall
For the 2010 Fiscal Year, we had a loss applicable to common stock of $13.4 million, which was a $21.3 million decrease as compared to income applicable to common stock of $7.9 million for the 2009 Fiscal Year. Items contributing to the $21.3 million decrease were reduced gain on derivatives of $45.7 million, decreased income from preferred stock repurchased for less than the carrying amount of $10.9 million and lower income from discontinued operations of $10.3 million. Partially offsetting the earnings decrease were lower operating expenses of $43.9 million, which is primarily attributable to a $26.7 million charge for impairment of long-lived assets during the 2009 Fiscal Year. Other items that decreased operating expenses were reductions to general and administrative expenses of $7.3 million, decreased exploration expense of $6.4 million and lower lease operating expenses of $2.8 million.
For the 2009 Fiscal Year, we had income applicable to common stock of $7.9 million, which was a $29.5 million improvement as compared to the $21.6 million loss applicable to common stock for the 2008 Fiscal Year. Items that led to the improvement were increased gain on derivatives of $75.7 million, preferred stock repurchased for less than the carrying amount of $10.9 million, higher income from discontinued operations of $7.1 million and lower preferred stock dividend of $1.4 million. These positive factors were partially offset by higher operating expenses of $49.7 million, lower operating revenues of $7.9 million, lower deferred income tax benefit of $7.5 million and goodwill impairment of $0.7 million.
Operating Revenues
The table below summarizes our operating revenues:
2010 Fiscal Year v. 2009 Fiscal Year
The 2010 Fiscal Year operating revenues of $22.8 million were $0.6 million lower as compared to the 2009 Fiscal Year operating revenues of $23.4 million. The $0.6 million reduction is primarily attributable to decreased crude oil and natural gas sales volumes, which lowered revenues by $1.6 million and $0.9 million, respectively, and lower other revenues of $0.3 million. These decreases were partially offset by increased prices received for crude oil and natural gas sales volumes of $2.1 million and $0.2 million, respectively.
Crude Oil Sales. Our 2010 Fiscal Year crude oil sales were 23 MBbls lower as compared to the 2009 Fiscal Year due to lower sales from our Cato Properties and Panhandle Properties of 12 MBbls and 8 MBbls, respectively. The sales decrease at our Cato Properties resulted from the redistribution of water injection at the waterflood which resulted in lower production, as discussed under “Overview-Drilling Capital Development and Operating Activities Update.”
The sales decrease at the Panhandle Properties is due to the controlled injection project at the Cockrell Ranch waterflood and severe weather during January and February 2010 which temporarily curtailed production. All Cockrell Ranch production that had been temporarily shut-in for the controlled injection project was restored on September 28, 2009.
Natural Gas Sales. Our 2010 Fiscal Year natural gas sales were 119 MMcf lower as compared to the 2009 Fiscal Year primarily due to lower sales at the Panhandle Properties of 44 MMcf, Desdemona Properties of 36 MMcf and Cato Properties of 36 MMcf. Lower natural gas sales at the Panhandle Properties resulted from severe weather and from the controlled production project at Cockrell Ranch waterflood, as previously discussed, and one of our gas purchasers experiencing unplanned plant outages during August 2009, September 2009, May 2010 and June 2010, which resulted in reduced natural gas and NGL sales. Lower natural gas sales at the Desdemona Properties resulted from the shut-in natural gas production from our Barnett Shale wells during July 2009, based upon the then current and near-term outlook of natural gas prices, and the temporary shut-in of our gas plant to equip the plant to handle increased natural gas production from the return to production of 25 shut-in Duke Sand gas wells as previously discussed under the “Overview-Drilling Capital Development and Operating Activities Update.” Lower natural gas sales at the Cato Properties resulted from the purchaser temporarily declining to take natural gas production from January through March 2010.
2009 Fiscal Year v. 2008 Fiscal Year
The 2009 Fiscal Year operating revenues of $23.4 million were $7.9 million lower as compared to the 2008 Fiscal Year operating revenues of $31.3 million. The $7.9 million reduction is primarily attributable to lower prices received for crude oil and natural gas sales, which lowered revenues by $7.9 million and $3.0 million, respectively, and by lower natural gas sales volumes, which lowered revenues by $0.7 million. These decreases were partially offset by increased crude oil sales volumes, which increased revenues by $3.7 million.
Crude Oil Sales. For the 2009 Fiscal Year, approximately 82% of the increased crude oil sales of 60 MBbls were attributed to the waterflood development activity at the Cato Properties. Also, we had increased crude oil sales from the Panhandle Properties due to the waterflood development.
Natural Gas Sales. For the 2009 Fiscal Year, the overall decrease in natural gas sales of 96 MMcf pertains primarily to reductions with respect to our Barnett Shale project at our Desdemona Properties. During the first half of calendar year 2008, various workovers and re-fracture stimulations were attempted to increase production. Through December 2008, these efforts were met with marginal success. In January 2009, we halted our workover program in the Desdemona Properties-Barnett Shale. Once the Barnett Shale workover activity ceased, we experienced Barnett Shale production declines of approximately 65 - 90%.
Also, higher gas production from the Cato Properties due to the aforementioned development activity was offset by lower gas production from our Panhandle Properties due to normal field decline of approximately 10% annually and temporary pipeline curtailments of gas deliveries to our gas purchasers.
Crude Oil and Natural Gas Prices
The average price we receive for crude oil sales is generally at market prices received at the wellhead, except for the Cato Properties, for which we receive below market prices due to the level of impurities in the oil. Differentials increased briefly as commodity prices rapidly declined between July 2008 and December 2008; however, the differentials have since recovered. The average price we receive for natural gas sales is approximately the market price received at the wellhead, adjusted for the value of natural gas liquids, less transportation and marketing expenses.
The average prices we received for our crude oil and natural gas sales were supplemented or reduced by commodity derivative settlements received or paid for the 2010, 2009 and 2008 Fiscal Years. As discussed in Note 6 to our Consolidated Financial Statements, if crude oil and natural gas NYMEX prices are lower than the “floor prices,” we will be reimbursed by our counterparty for the difference between the NYMEX price and “floor price” (i.e. realized gain). Conversely, if crude oil and natural gas NYMEX prices are higher than the derivative “ceiling prices,” we will pay our counterparty for the difference between the NYMEX price and “ceiling price” (i.e. realized loss).
Operating Expenses
2010 Fiscal Year v. 2009 Fiscal Year
For the 2010 Fiscal Year, our total operating expenses were $40.0 million, or $43.9 million lower than the 2009 Fiscal Year of $83.8 million. The 2009 Fiscal Year included an impairment of long-lived assets of $26.7 million, which is the primary reason for the overall decrease. In addition, we had reduced general and administrative of $7.3 million, reduced exploration expense of $6.4 million, lower lease operating expenses of $2.8 million and lower depletion and depreciation expense of $0.8 million.
2009 Fiscal Year v. 2008 Fiscal Year
For the 2009 Fiscal Year, our total operating expenses were $83.8 million, or $49.7 million higher than the 2008 Fiscal Year of $34.1 million. The primary contributors to the increase were an impairment of long-lived assets of $26.7 million and exploration expense of $11.4 million associated with the Desdemona Properties-Duke Sands waterflood project. In addition, we experienced increased lease operating expenses of $5.5 million, general and administrative of $4.3 million and higher depletion and depreciation of $1.8 million.
Lease Operating Expenses
Our lease operating expenses (“LOE”) consist of the costs of producing crude oil and natural gas such as labor, supplies, repairs, maintenance, workovers and utilities.
For the 2010 Fiscal Year, our LOE was $15.7 million, which is $2.8 million lower than 2009 Fiscal Year of $18.5 million. The $2.8 million decrease resulted primarily from reduced service rates negotiated with vendors of $2.5 million, the shut-in of our Barnett Shale natural gas wells which reduced LOE by $0.6 million and lower electricity expense of $0.3 million. Partially offsetting these LOE cost reductions were increased LOE at the Cato Properties of $0.6 million to support increased focus on production activities.
For the 2010 Fiscal Year, our LOE per BOE, based on production, was reduced by $5.55 per BOE to $38.90 as compared to $44.45 for the 2009 Fiscal Year for the reasons previously discussed. For the quarter ended June 30, 2010, the LOE per BOE was $36.35. In general, secondary and tertiary LOE is higher than the LOE for companies developing primary production because our fields are more mature and typically produce less oil and more water. However, we expect our LOE per BOE to decrease during the 2011 Fiscal Year as we realize the benefit of a full year of lower service rates with vendors. Further, we expect LOE per BOE to decrease as production increases from the waterflood and EOR development activities we have implemented and are implementing as discussed under the “Drilling Capital Development and Operating Activities Update.”
For the 2009 Fiscal Year, our LOE was $18.5 million, which is $5.5 million higher than 2008 Fiscal Year of $13.0 million. The $5.5 million increase resulted primarily from increased workover activities and general repairs at the Panhandle Properties of $4.2 million and higher operating expenses incurred at the Cato Properties of $2.1 million to support increased crude oil and natural gas sales, as discussed under “Operating Revenues,” partially offset by lower operating expenses of $1.1 million due to lower natural gas sales at the Desdemona Properties, as discussed under “Operating Revenues.” We also had higher LOE at the Davenport and Nowata Properties of $0.3 million due to increased electricity expenses, general repairs and workover expenses. The workover activities at the Panhandle Properties pertained to returning wells to production and have increased production, as discussed under “Operating Revenues.” For the 2009 Fiscal Year, our LOE per BOE was $44.45, which is an $8.38 per BOE increase as compared to $36.07 for Fiscal Year 2008. The $8.38 per BOE increase is due to the reasons previously discussed.
Production and Ad Valorem Taxes
For the 2010 Fiscal Year, our production and ad valorem taxes were $1.9 million, which is $0.2 million lower than the 2009 Fiscal Year of $2.1 million. Our production taxes were lower by $0.1 million due to lower operating revenues and ad valorem taxes were lower by $0.1 million due to reductions in tax property valuations by taxing authorities. Our production taxes as a percent of operating revenues for the 2010 Fiscal Year of 6.3% was comparable to the 2009 Fiscal Year of 6.5%. We anticipate the 2011 Fiscal Year to be subject to similar production tax rates.
For the 2009 Fiscal Year, our production and ad valorem taxes were $2.1 million, which is comparable to 2008 Fiscal Year. Our production taxes were lower by $0.5 million due to lower operating revenues, which was offset by increased ad valorem taxes of $0.5 million. The increased ad valorem taxes were due to notification of revisions in tax property valuations by taxing authorities for the 2008 calendar year. Therefore, the 2009 Fiscal Year includes higher tax rates for the twelve months plus a charge for applying the rates to the first six months of the 2008 calendar year. Our production taxes as a percent of operating revenues for the 2009 Fiscal Year of 6.5% was comparable to the 2008 Fiscal Year of 6.6%.
General and Administrative Expenses
Our general and administrative (“G&A”) expenses consist of support services for our operating activities, legal matters and investor relations costs.
2010 Fiscal Year v. 2009 Fiscal Year
For the 2010 Fiscal Year, our G&A expenses totaled $11.8 million, which is $7.3 million lower than Fiscal Year 2009 of $19.2 million. The $7.3 million expense reduction resulted primarily from reduced litigation costs of $6.0 million, reduced share-based compensation costs of $2.1 million, and lower payroll and benefits costs of $0.9 million. Partially offsetting these expense reductions were increased costs related to the terminated merger of $2.1 million. The reduced payroll and benefits costs resulted from workforce reductions we implemented during the quarter ended March 31, 2009, which eliminated 25% of our home office staff. The lower share-based compensation costs are directly related to reduced issuances
of stock options and restricted stock. The litigation cost reduction occurred as we settled all but one of our fire litigation claims during the fiscal year ended June 30, 2009.
2009 Fiscal Year v. 2008 Fiscal Year
For the 2009 Fiscal Year, our G&A expenses totaled $19.2 million, which is $4.3 million higher than Fiscal Year 2008 of $14.9 million. The primary contributors to the $4.3 million increase were higher litigation costs of $4.4 million pertaining to the settlement costs and legal fees pertaining to the fire litigation and increased stock compensation expense of $0.2 million, partially offset by reduced payroll expense of $0.3 million. During the quarter ended March 31, 2009, we took steps to reduce our payroll, eliminating 25% of our home office staff. The quarter ended June 30, 2009 was the first time we realized these savings.
Exploration Expense
During the 2010 Fiscal Year, we recorded exploration expense of $5.0 million pertaining to the Nowata ASP Project. During December 2009, we finalized our performance analysis, which indicated the Nowata ASP Project did not result in significantly increased oil production quantities and is therefore considered not economically viable. Accordingly, at December 31, 2009, we recorded a $5.0 million pre-tax exploration expense.
During the 2009 Fiscal Year, we recorded exploration expense of $11.4 million pertaining to the Duke Sand waterflood project. The primary source of water for this waterflood project had been derived from our Barnett Shale wells. As we shut-in our Barnett Shale natural gas production due to uneconomic natural gas commodity prices, we no longer had an economic source of water to continue flooding the Duke Sand. Therefore, our rate of water injection had been reduced to a point where we could not consider the waterflood active. We continue to believe that this reservoir is an excellent secondary and tertiary recovery candidate; however, we do not have plans to recommence injection for the foreseeable future.
Impairment of Long-Lived Assets
During the 2010 Fiscal Year, we wrote down $0.3 million of costs associated with the ASP facility used for the Nowata ASP Project. The facility’s water filtering process did not work properly with the oil-water fluid production at our Nowata Properties. The ASP facility is portable and may be used in future pilot tertiary projects at our Cato and Panhandle Properties.
During the 2009 Fiscal Year, we recorded a $26.7 million impairment on our Barnett Shale Properties as the decline in commodity prices created an uncertainty about the likelihood of developing our reserves associated with our Barnett Shale natural gas properties within the next five years. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline and we shut-in our Barnett Shale natural gas wells. The fair value was determined using estimates of future production volumes, prices and operating expenses, discounted to a present value.
Depletion and Depreciation
For the 2010 Fiscal Year, our depletion and depreciation expense was $5.0 million, a decrease of $0.7 million as compared to the 2009 Fiscal Year depletion and depreciation expense. This includes depletion expense pertaining to our oil and natural gas properties, and depreciation expense pertaining to our field operations vehicles and equipment, natural gas plant, office furniture and computers. The decrease is due to decreased crude oil and natural gas sales volumes (net) as previously discussed under “Operating Revenues.” For the 2010 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $13.99 per BOE, as compared to the 2009 Fiscal Year rate of $14.20 per BOE. The decreased depletion rates resulted primarily from our reserve redetermination at December 31, 2009 and periodic assessments of depletion rates during the 2010 Fiscal Year, and impairments of our Barnett Shale Properties, as previously discussed.
For the 2009 Fiscal Year, our depletion and depreciation expense was $5.7 million, an increase of $1.8 million as compared to the 2008 Fiscal Year depletion and depreciation expense. The increase is due to increased crude oil and natural gas sales volumes (net) as previously discussed under “Operating Revenues” and higher per BOE depletion rates. For the 2009 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $14.20 per BOE, as compared to the 2008 Fiscal Year rate of $10.88 per BOE. The increased depletion rates resulted from higher depletion rates for our Cato and Panhandle Properties based on our reserve estimates at June 30, 2009 and periodic assessments of depletion rates during the 2009 Fiscal Year.
Interest Expense and Other
For the 2010, 2009 and 2008 Fiscal Years, we recorded interest expense of $1.0 million, $0.5 million and $0.7 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 5 to our Consolidated Financial Statements. The interest expense for the 2010, 2009 and 2008 Fiscal Years was reduced by $2.0 million, $1.4 million and $2.5 million, respectively, for interest cost that was capitalized to the waterflood and ASP projects discussed under the “Drilling Capital Development and Operating Activities Update.” We incurred higher interest costs during both the 2010 and 2008 Fiscal Years due to higher outstanding debt balances and higher interest rates.
Gain (Loss) on Commodity Derivatives
As discussed in Note 6 to our Consolidated Financial Statements, we have entered into financial contracts for our commodity derivatives and our interest rate swap. For the 2010 Fiscal Year, the loss on commodity derivatives of $1.9 million consisted of an unrealized loss of $6.6 million and a realized gain of $4.7 million. For the 2009 Fiscal Year, the gain on commodity derivatives of $43.8 million consisted of an unrealized gain of $36.9 million and a realized gain on settlements of commodity derivative contracts of $6.9 million. For the 2008 Fiscal Year, the loss on commodity derivatives of $32.0 million consisted of unrealized and realized losses of $29.4 million and $2.6 million, respectively.
For the realization of settlements, if crude oil and natural gas NYMEX prices are lower than the floor prices, we will be reimbursed by our counterparty for the difference between the NYMEX price and floor price (i.e. realized gain). Conversely, if crude oil and natural gas NYMEX prices are higher than the ceiling prices, we will pay our counterparty for the difference between the NYMEX price and ceiling price (i.e. realized loss).
The unrealized gain for the 2010 Fiscal Year reflects the change in fair value of the commodity derivatives during the 2010 Fiscal Year. By their nature, these commodity derivatives can have a highly volatile impact on our earnings. A ten percent change in the NYMEX prices for crude oil and natural gas that impact our commodity derivative instruments could affect our pre-tax earnings by approximately $5.0 million.
Income Tax Benefit (Expense)
For the 2010 Fiscal Year, we had an income tax benefit of $5.3 million. For the 2009 Fiscal Year, we had income tax expense of $1.7 million. For the 2008 Fiscal Year, we had an income tax benefit of $9.8 million. These tax amounts included taxes related to discontinued operations as shown in Note 7 to our Consolidated Financial Statements. The higher amount of income taxes for the 2009 Fiscal Year, as compared to the 2010 and 2008 Fiscal Years, is due to higher taxable income and an increase in other permanent items, as presented in Note 14 to our Consolidated Financial Statements, resulting in an aggregate rate of 107.4%. The income tax rates for the 2010 and 2008 Fiscal Years was 31.3% and 35.8%, respectively.
Income from Discontinued Operations
For the 2010, 2009 and 2008 Fiscal Years, we had income from discontinued operations of $2.1 million, $12.3 million and $5.2 million, respectively, due to our divestitures of the Pantwist, LLC; Corsicana Properties and Certain Panhandle Properties, as discussed in Note 7 to our Consolidated Financial Statements.
Preferred Stock Dividend
The preferred stock dividend for the 2010 Fiscal Year of $1.8 million was a decrease of $0.9 million from the 2009 Fiscal Year. This resulted from the November and December 2008 repurchases of preferred stock as discussed in Note 4 to our Consolidated Financial Statements. Due to the repurchases, our quarterly preferred stock dividends will be approximately $0.5 million per quarter of which 59% will be paid-in-kind, with the balance paid in cash.
The preferred stock dividend for the 2009 Fiscal Year of $2.7 million was a decrease of $1.4 million from the 2008 Fiscal Year. This resulted from the November and December 2008 repurchases of preferred stock, as previously discussed. Also, the 2008 Fiscal Year amount includes $0.5 million of federal tax we were required to withhold in accordance with Internal Revenue Service regulations from September 2006 through June 2008. These amounts did not have a material effect to our prior period financial statements. Due to the previously discussed repurchases, we no longer have any Preferred Stock that require withholding taxes.
On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.
Contractual Obligations
The following table sets forth our contractual obligations in thousands at June 30, 2010 for the periods shown:
Off Balance Sheet Arrangements
Our off balance sheet arrangements are limited to operating leases that have not and are not reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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.
(a) For the quarter ended December 31, 2009, our results of operations were unfavorably impacted by unrealized loss on commodity derivatives of $5.8 million.
(b) For the quarter ended September 30, 2008, our results of operations were favorably impacted by $24.2 million unrealized gain on commodity derivatives resulting from a significant price decrease for both crude oil and natural gas.
(c) For the quarter ended December 31, 2008, our results of operations were unfavorably impacted by impairment of long-lived assets of $22.4 million, partially offset by unrealized gain on commodity derivatives.
(d) For the quarter ended June 30, 2009, our results of operations were unfavorably impacted by exploration expense of $11.4 million and impairment of long-lived assets of $4.3 million.
Critical Accounting Policies
We have identified the critical accounting policies used in the preparation of our financial statements. These are the accounting policies that we have determined involve the most complex or subjective decisions or assessments.
Consolidation and Use of Estimates
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Cano and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved crude oil and natural gas reserves, which may affect the amount at which crude oil and natural gas properties are recorded. The computation of share-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. Our liabilities and assets associated with commodity derivatives involve significant assumptions related to volatility and future prices for crude oil and natural gas. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.
Cano’s Proved Reserves
The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices based on an unweighted 12-month average and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases. A decline in estimates of proved reserves may result from lower prices, new information obtained from development drilling and production history; mechanical problems on our wells; and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserves estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserves estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.
Oil and Gas Properties and Equipment
We follow the successful efforts method of accounting. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense. The costs of drilling and equipping exploratory wells are deferred until the Company has determined whether proved reserves have been found. If proved reserves are found, the deferred costs are capitalized as part of the wells and related equipment and facilities. If no proved reserves are found, the deferred costs are charged to expense. All development activity costs are capitalized. We are primarily engaged in the development and acquisition of crude oil and natural gas properties. Our activities are considered development where existing proved reserves are identified prior to commencement of the project and are considered exploration if there are no proved reserves at the beginning of such project. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisition and development activities and deferred exploratory drilling costs. Capitalized overhead costs that directly relate to our drilling and development activities were $0.8 million and $1.1 million for the years ended June 30, 2010 and 2009, respectively. We recorded capitalized interest costs of $2.0 million and $1.4 million for the years ended June 30, 2010 and 2009, respectively.
Costs for repairs and maintenance to sustain or increase production from existing producing reservoirs are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Depreciation and depletion of producing properties are computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Our unit-of-production amortization rates are revised prospectively on a quarterly basis based on updated engineering information for our proved developed reserves. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until impairment occurs. As of June 30, 2010 and 2009, capitalized costs related to waterflood and alkaline-surfactant-polymer (“ASP”) projects that were in process and not subject to depletion amounted to $51.6 million and $49.4 million, respectively, of which $0.0 million and $4.8 million, respectively, were deferred costs related to drilling and equipping exploratory wells associated with our ASP project, as discussed in Note 8 to our Consolidated Financial Statements.
If conditions indicate that long-term assets may be impaired, the carrying value of our properties is compared to management’s future estimated undiscounted net cash flow from the properties. If undiscounted cash flows are less than the carrying value, then the asset value is written down to fair value. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis. The impairment assessment is affected by factors such as the results of exploration and development activities, commodity price projections, remaining lease terms, and potential shifts in our business strategy.
Asset Retirement Obligation
Our financial statements reflect the fair value of our asset retirement obligation (“ARO”), which consists of future plugging and abandonment expenditures related to our oil and gas properties, that can be reasonably estimated, and discounted at our credit-adjusted risk-free rate. The asset retirement obligation is recorded as a liability at its estimated fair value at the asset’s inception, with an offsetting increase to producing properties on the consolidated balance sheets, which is depreciated such that the cost of the ARO is recognized over the useful life of the asset. Periodic accretion of the discount of the estimated liability to its expected settlement value is recorded as an expense in the consolidated statements of operations.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
Revenue Recognition
Our revenue recognition is based on the sales method. We do not have imbalances for natural gas sales since we are primarily the 100% working interest owner in our properties. We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on publicly available information. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from the purchasers are collectible. The point of sale for our crude oil and natural gas production is at our applicable field tank batteries and gathering systems; therefore, we do not incur transportation costs related to our sales of crude oil and natural gas production.
As previously discussed, for the years ended June 30, 2010, 2009 and 2008, we sold our crude oil and natural gas production to several independent purchasers. The following table shows purchasers that accounted for 10% or more of our total operating revenues:
* Less than 10% of operating revenue
Share-Based Compensation Expense
We account for share-based payment arrangements with employees and directors at their grant-date fair value and record the related expense over their respective service periods. The value of share-based compensation is impacted by our stock price, which has been highly volatile, and items that require management’s judgment, such as expected lives and forfeiture rates.
Derivatives
We are required to maintain commodity derivative contracts for a portion of our crude oil and natural gas production under our senior and subordinated credit agreements, as discussed in Note 5 to our Consolidated Financial Statements. The purpose of the derivatives is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect our cash flows which support our annual capital expenditure plans. We have entered into commodity derivatives that involve “costless collars and swaps” for our crude oil and natural gas sales. These derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets based upon their respective fair values. We have entered into an interest rate basis swap contract to reduce our exposure to future interest rate increases.
We do not designate our derivatives as cash flow or fair value hedges. We do not hold or issue derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparties to our commodity and interest rate swap derivatives. We anticipate, however, that our counterparties will be able to fully satisfy their respective obligations under our commodity and interest rate swap derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts nor are we required to post any collateral. We monitor the credit standing of our counterparties to understand our credit risk.
Changes in the fair values of our derivative instruments and cash flows resulting from the settlement of our derivative instruments are recorded in earnings as gains or losses on derivatives on our consolidated statements of operations.
New Accounting Pronouncements
In March 2008, the FASB issued ASC 815 (formerly SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement 133). ASC 815 expands the required disclosures to discuss the uses of derivative instruments, the accounting for derivative instruments and related hedged items under ASC 815, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.
In June 2008, the FASB issued ASC 260 (formerly EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities). ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of earnings per share under the two-class method. Under ASC 260, share-based payment awards that contain nonforfeitable rights to dividends are “participating securities”, and therefore should be included in computing earnings per share using the two-class method. ASC 260 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 260 on July 1, 2009. The effect of adopting ASC 260 increased the number of shares used to compute our earnings per share; however, the adoption of ASC 260 did not have a material impact on our financial position, results of operations or cash flows.
In December 2008, the FASB issued ASC 815 (formerly EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock). ASC 815 affects companies that have provisions in their securities purchase agreements (e.g. convertible instruments) that provide for the reset of the current conversion price based upon new issuances by companies at prices below the current conversion price of said instrument. Securities purchase agreements with such provisions will require the embedded derivative instrument to be bifurcated and separately accounted for as a derivative. Subject to certain exceptions, our preferred stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. ASC 815 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows as the reset conversion provision did not meet the definition of a derivative since it was not readily net-cash settled.
On December 31, 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserve preparer or auditor and file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit. The new rules also require that oil and gas reserves be reported using a twelve-month average price rather than period-end prices. The new rules are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. Additionally, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosures, as set forth in ASU No. 2010-03, Extractive Activities-Oil and Gas (Topic 932), to align with the requirements of the SEC’s revised rules. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.
In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820). ASU 2010-06 Subtopic 820-10 provides new guidance on improving disclosures about fair value measurements. The new standard requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement. Specifically, the new standard will now require: (a) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for transfers and (b) in the reconciliation for fair value measurements using significant unoberservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, the new standard clarifies the requirements of the following existing disclosures: (a) for purposes of reporting fair value measurements for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities and (b) a reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The adoption of the requirements of this standard in the quarter ended March 31, 2010 did not have a material impact on our financial position or results of operations.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
Item 8.
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 of this annual report on Form 10-K and are incorporated herein.
The financial statement schedules have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes to our Consolidated Financial Statements.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) that are designed to ensure that information required to be disclosed by us in the reports filed or submitted under the Securities Exchange Act of 1934 is (i) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and (ii) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based on that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures as of June 30, 2010 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 Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethics and Business Conduct for Officers, Directors and Employees, which sets the tone of our Company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail accurately and fairly reflect our acquisitions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
In order to evaluate the effectiveness of our internal control over financial reporting as of June 30, 2010, 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, 2010 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.
Changes in Internal Controls
During the quarter ended June 30, 2010, there was no change in our internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Information required by this item relating to our (i) directors and executive officers, (ii) audit committee, (iii) Code of Ethics and Business Conduct, (iv) changes in procedures by which security holders may recommend nominees to our board of directors, and (v) compliance with Section 16(a) of the Securities Exchange Act will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to our 2010 annual meeting of stockholders and will be incorporated herein by reference.
Item 11.
Item 11. Executive Compensation.
Information required by this item relating to executive compensation will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2010 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information required by this item relating to (i) security ownership of certain beneficial owners and management and (ii) securities authorized for issuance under equity compensation plans will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2010 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required by this item relating to (i) certain business relationships and related transactions with management and other related parties and (ii) director independence will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to the 2010 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information relating to (i) fees billed to the Company by the independent registered public accounting firm for services for the years ended June 30, 2010 and 2009 and (ii) the audit committee’s pre-approval policies and procedures for audit and non-audit services, will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our definitive proxy statement relating to our 2010 Fiscal Year annual meeting of stockholders and will be incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as part of this report:
1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of June 30, 2010 and 2009, Consolidated Statements of Operations for each of the three years in the period ended June 30, 2010, Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended June 30, 2010, Consolidated Statements of Cash Flows for each of the three years in the period ended June 30, 2010, and Notes to Consolidated Financial Statements.
2. The financial statement schedules have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes to Consolidated Financial Statements.
3. The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
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.
Pursuant to the requirements of 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.
Date: September 22,
By:
/s/ BENJAMIN DAITCH
Benjamin Daitch
Senior Vice-President and
Chief Financial Officer
Date: September 22,
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 Benjamin Daitch or either of them (with full power to each of them to act alone), his true and lawful attorney-in-facts and agents, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file any and all amendments to this Form 10-K, with all exhibits thereto, and other documents in connection therewith, with the SEC, granting unto said attorneys, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as full to all intents and purposes as he himself might or could do if personally present, thereby ratifying and confirming all that said attorneys-in-fact and agents, or either of them, or their or his substitute or substitutes, may lawfully do or cause to be done.
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/S/ S. JEFFREY JOHNSON
Chairman of the Board
September 22, 2010
S. Jeffrey Johnson
/s/ RANDALL BOYD
Director
September 22, 2010
Randall Boyd
/s/ ROBERT L. GAUDIN
Director
September 22, 2010
Robert L. Gaudin
/s/ DONALD W. NIEMIEC
Director
September 22, 2010
Donald W. Niemiec
/s/ WILLIAM O. POWELL III
Director
September 22, 2010
William O. Powell III
/s/ GARRETT SMITH
Director
September 22, 2010
Garrett Smith
/s/ DAVID W. WEHLMANN
Director
September 22, 2010
David W. Wehlmann
INDEX TO EXHIBITS
Exhibit
Number
Description
3.1
Certificate of Incorporation of Huron Ventures, Inc., incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 10 SB (File No. 000-50386) filed with the SEC on September 4, 2003.
3.2
Certificate of Ownership of Huron Ventures, Inc. and Cano Petroleum, Inc., amending the Company’s Certificate of Incorporation, incorporated herein by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-KSB filed with the SEC on September 23, 2004.
3.3
Certificate of Amendment to Certificate of Incorporation of Cano Petroleum, Inc., incorporated herein by reference to Exhibit 3.8 to the Company’s Post-Effective Amendment No. 2 on Form S-1 filed with the SEC on January 23, 2007.
3.4
Second Amended and Restated By-Laws of Cano Petroleum, Inc. dated May 7, 2009, incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 13, 2009.
3.5
Certificate of Designation for Series B Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 8, 2004.
3.6
Certificate of Designation for Series C Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 15, 2004.
3.7
Certificate of Designation for Series D Convertible Preferred Stock, incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 7, 2006.
3.8
Certificate of Amendment to Certificate of Designations, Preferences and Rights of Series D Convertible Preferred Stock of the Company, incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2010.
4.3
Form of Common Stock certificate, incorporated herein by reference to Exhibit 4.9 to the Company’s Registration Statement on Form S-3 (No. 333-148053) filed with the SEC on December 13, 2007.
4.4
Designation for Series A Convertible Preferred Stock, included in the Certificate of Incorporation of Huron Ventures, Inc., incorporated herein by reference to Exhibit 3.1 to the Company’s registration statement on Form 10 SB (File No. 000-50386) filed with the SEC on September 4, 2003.
4.5
Certificate of Designation for Series B Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 8, 2004.
4.6
Certificate of Designation for Series C Convertible Preferred Stock, incorporated herein by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 15, 2004.
4.7
Certificate of Designation for Series D Convertible Preferred Stock incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 7, 2006.
4.8
Certificate of Amendment to Certificate of Designations, Preferences and Rights of Series D Convertible Preferred Stock of the Company, incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2010.
10.1+
Stock Option Agreement dated December 16, 2004 between Cano Petroleum, Inc. and Gerald W. Haddock, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 16, 2004.
10.2+
2005 Directors’ Stock Option Plan, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 28, 2005.
10.3+
Cano Petroleum, Inc. 2005 Long-Term Incentive Plan dated December 7, 2005, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 9, 2005.
10.4+
Form of Non-Qualified Stock Option Agreement under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 19, 2005.
10.5+
Employment Agreement dated effective January 1, 2006 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 19, 2006.
10.7+
Employment Agreement of Patrick M. McKinney effective June 1, 2006, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 9, 2006.
10.8+
First Amendment to Employment Agreement of Patrick M. McKinney dated November 9, 2006, incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on November 9, 2006.
10.10+
Employment Agreement of Michael J. Ricketts effective July 1, 2006, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 17, 2006.
10.13+
Amendment No. 1 to the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan dated December 28, 2006, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.14+
Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.18+
Nonqualified Stock Option Agreement dated December 28, 2006 between Cano Petroleum, Inc. and Michael J. Ricketts, incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the SEC on January 4, 2007.
10.21+
Nonqualified Stock Option Agreement of Randall C. Boyd dated December 28, 2006, incorporated herein by reference to Exhibit 10.77 to the Company’s Post-Effective Amendment No. 2 on Form S-1 (File No. 333-126167) filed with the SEC on January 23, 2007.
10.25+
Nonqualified Stock Option Agreement of William O. Powell III dated April 4, 2007, incorporated herein by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.
10.26+
Nonqualified Stock Option Agreement of Robert L. Gaudin dated April 4, 2007, incorporated herein by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.
10.27+
Nonqualified Stock Option Agreement of Donald W. Niemiec dated April 4, 2007, incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 9, 2007.
10.30+
Form of Restricted Stock Award under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2007.
10.31+
Form of Nonqualified Stock Option Agreement under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2007.
10.32+
Second Amendment to Employment Agreement of Patrick M. McKinney dated June 29, 2007, incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 3, 2007.
10.33+
First Amendment to Employment Agreement of Michael J. Ricketts dated June 29, 2007, incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on July 3, 2007.
10.34+
Form of the First Amendment to the Cano Petroleum, Inc. Employee Restricted Stock Award Agreement, incorporated herein by reference to Exhibit 10.96 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.35+
Form of Restricted Stock Award under the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, incorporated herein by reference to Exhibit 10.97 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.38+
First Amendment dated June 28, 2007 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of James Dale Underwood dated December 13, 2005 incorporated herein by reference to Exhibit 10.103 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.39+
First Amendment dated June 28, 2007 to the Cano Petroleum, Inc. Nonqualified Stock Option Agreement of James Underwood dated December 28, 2006, incorporated herein by reference to Exhibit 10.104 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2007.
10.51
$25,000,000 Subordinated Credit Agreement dated March 17, 2008 among Cano Petroleum, Inc. as Borrower, the Lenders Party Hereto from Time to Time as Lenders, and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.52
Subordinated Security Agreement dated March 17, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.53
Subordinated Pledge Agreement dated March 17, 2008 among Cano Petroleum, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc. and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.54
Subordinated Guaranty Agreement dated March 17, 2008 by Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., and W.O. Production Company, Ltd., in favor of UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.55
Consent Agreement dated February 21, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., Union Bank of California, N.A. and Natixis, incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 8, 2008.
10.56+
First Amendment dated May 31, 2008 to Employment Agreement of S. Jeffrey Johnson dated January 1, 2006, incorporated herein by reference to Exhibit 10.84 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.57+
Third Amendment dated May 31, 2008 to Employment Agreement of Patrick M. McKinney dated June 29, 2007, as amended, incorporated herein by reference to Exhibit 10.86 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.58+
Fourth Amendment dated May 31, 2008 to Employment Agreement of Michael J. Ricketts dated May 28, 2004, as amended, incorporated herein by reference to Exhibit 10.87 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.59+
Employment Agreement of Phillip Feiner dated May 31, 2008, incorporated herein by reference to Exhibit 10.88 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.60+
Employment Agreement of Benjamin Daitch dated June 23, 2008, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2008.
10.61+
Restricted Stock Agreement of Benjamin Daitch dated June 23, 2008, incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2008.
10.62
Consent and Amendment No. 1 dated June 27, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.94 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.63
Amendment No. 2 dated effective June 30, 2008 among Cano Petroleum, Inc., Ladder Companies, Inc., Square One Energy, Inc., WO Energy, Inc., W.O. Energy of Nevada, Inc., Cano Petro of New Mexico, Inc., Pantwist, LLC, W.O. Operating Company, Ltd., W.O. Production Company, Ltd., and UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.95 to the Company’s Annual Report on Form 10-K filed with the SEC on September 11, 2008.
10.65
Amendment 11 to Valero # 01-0838 dated June 12, 2006 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.97 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.66
Amendment 12 to Valero # 01-0838 dated August 23, 2006 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company, incorporated herein by reference to Exhibit 10.98 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.67
Amendment 13 to Valero # 01-0838 dated August 31, 2007 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.99 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.68
Amendment 14 to Valero # 01-0838 dated January 25, 2008 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.100 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.69
Amendment 15 to Valero # 01-0838 dated August 1, 2008 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.101 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.70
Amendment 16 to Valero # 01-0838 dated April 3, 2009 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company, incorporated herein by reference to Exhibit 10.102 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.71
Amendment 17 to Valero # 01-0838 dated May 1, 2009 between W.O. Operating Company, Ltd. and Valero Marketing and Supply Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.103 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.72
Gas Purchase Agreement dated April 1, 2007 between Eagle Rock Field Services, L.P. and W.O. Operating Company, Ltd. and Pantwist, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.104 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.73
Letter Agreement dated March 25, 2009 Regarding Gas Purchase Agreement dated April 1, 2007 Eagle Rock Contract (#50038 Schafer) between Eagle Rock Energy Partners and W.O. Operating Company, Ltd. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.105 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.74
Letter Agreement dated April 30, 2009 Regarding Gas Purchase Agreement dated April 1, 2007 Eagle Rock Contract (#50038 Schafer) between Eagle Rock Energy Partners and W.O. Operating Company, Ltd., incorporated herein by reference to Exhibit 10.106 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009
10.76
Letter Agreement Regarding Crude Oil Purchase Agreement for Ladder Energy Operated Leases, dated January 15, 2009 between Ladder Energy Companies, Inc. and Coffeyville Resources Refinery and Marketing, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.108 to Amendment No. 2 to the Company’s Annual Report on Form 10-K/A filed with the SEC on July 6, 2009.
10.77
Letter Agreement Regarding Crude Oil Purchase Agreement for Ladder Energy Operated Leases, dated February 11, 2009 between Ladder Energy Companies, Inc. and Coffeyville Resources Refinery and Marketing, LLC (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.109 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.78
Letter Regarding Gas Purchase Contract No. PAM058500*, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.113 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.79
Letter Regarding Gas Purchase Contract No. BOR066300A, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.114 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.80
Letter Regarding Gas Purchase Contract No. BOR067500B, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.115 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.81
Letter Regarding Gas Purchase Contract No. BOR118000R, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.116 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.82
Letter Regarding Gas Purchase Contract No. BOR118100*, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.117 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.83
Letter Regarding Gas Purchase Contract No. BOR134200R, Panhandle Area, dated May 21, 2009 between W.O. Operating Company, Ltd. and DCP Midstream, incorporated herein by reference to Exhibit 10.118 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.84
Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated February 1, 2000 between Sunoco, Inc. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.119 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.85
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 2, 2005 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.120 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.86
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 26, 2006 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.121 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.87
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 502606 dated September 11, 2008 between Sunoco Partners Marketing & Terminals L.P. and Ladder Energy Company (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.122 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.88
Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated March 1, 2004 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.123 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.89
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated December 4, 2006 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy, Inc. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.124 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.90
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated February 16, 2009 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy, Inc. (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.125 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.91
Letter of Amendment to the Crude Oil Purchase Agreement Sunoco Reference No. 521329 dated April 2, 2009 between Sunoco Partners Marketing & Terminals L.P. and Square One Energy (confidential treatment has been requested for this exhibit and confidential portions have been filed with the SEC), incorporated herein by reference to Exhibit 10.126 to Amendment No. 2 to the Company’s Annual Report on Form 10 K/A filed with the SEC on July 6, 2009.
10.92+
Summary of 2009 Cash Incentive Awards, incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.93+
Consulting Agreement dated October 1, 2008 between Cano Petroleum, Inc. and Morris B. Smith, incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 6, 2008.
10.94+
Amendment to Employment Agreement of Phillip Feiner dated September 8, 2008, incorporated herein by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.95
Letter Agreement Regarding Payment of Prepayment Premium dated September 30, 2008 between Unionbancal Equities, Inc. and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 10, 2008.
10.96
Letter Agreement dated November 19, 2008 between Union Bank of California, NA and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 10-Q filed with the SEC on November 20, 2008.
10.97
Letter Agreement dated November 19, 2008 between Unionbancal Equities, Inc. and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 10-Q filed with the SEC on November 20, 2008.
10.98
Temporary Waiver of Benefits dated October 28, 2008 between S. Jeffrey Johnson and Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2009.
10.99+
First Amendment to the Cano Petroleum, Inc. 2008 Annual Incentive Plan dated October 20, 2008, incorporated herein by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.100
$120,000,000 Amended and Restated Credit Agreement dated December 17, 2008 among Cano Petroleum, Inc. as Borrower, The Lenders Party Thereto From Time to Time as Lenders, and Union Bank of California, N.A. as Administrative Agent, incorporated herein by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.101
$25,000,000 Subordinated Credit Agreement dated December 17, 2008 among Cano Petroleum, Inc. as Borrower, The Lenders Party Thereto From Time to Time as Lenders, and UnionBanCal Equities, Inc. as Administrative Agent and as Issuing Lender, incorporated herein by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.102
Amended and Restated Guaranty Agreement dated December 17, 2008 by Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. in favor of Union Bank of California, N.A. as Administrative Agent, incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.103
Subordinated Guaranty Agreement dated December 17, 2008 by Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., WO Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. in favor of UnionBanCal Equities, Inc. as Administrative Agent, incorporated herein by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.104
Amended and Restated Pledge Agreement dated December 17, 2008 among Cano Petroleum, Inc., WO Energy, Inc. and W.O. Energy of Nevada, Inc. and Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.105
Subordinated Pledge Agreement dated December 17, 2008 among Cano Petroleum, Inc., W.O. Energy, Inc. and W.O. Energy of Nevada, Inc. and UnionBanCal Equities, Inc., as Administrative Agent, incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.106
Amended and Restated Security Agreement dated December 17, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., W.O. Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. and Union Bank of California, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.107
Subordinated Security Agreement dated December 17, 2008 among Cano Petroleum, Inc., Square One Energy, Inc., Ladder Companies, Inc., W.O. Energy of Nevada, Inc., W.O. Energy, Inc., W.O. Operating Company, Ltd., W.O. Production Company, Ltd. and Cano Petro of New Mexico, Inc. and UnionBanCal Equities, Inc., as Administrative Agent, incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.108+
Second Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.109+
First Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Ben Daitch, incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.110+
Fourth Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Patrick M. McKinney, incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.111+
Fifth Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Michael J. Ricketts, incorporated herein by reference to Exhibit 10.18 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.112+
Second Amendment to Employment Agreement dated December 31, 2008 between Cano Petroleum, Inc. and Phillip Feiner, incorporated herein by reference to Exhibit 10.19 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on February 9, 2009.
10.113
Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 2.1 to Current Report on Form 8-K filed on October 1, 2009.
10.114
Gas Purchase Agreement by and between W.O. Operating Company Ltd. and DCP Midstream, L.P. effective on July 1, 2009, incorporated herein by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 13, 2009.
10.115
Stock Voting Agreement, dated as of September 29, 2009 by and between Cano Petroleum, Inc. and D.E. Shaw Laminar Portfolios, L.L.C., incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on October 1, 2009.
10.116+
Separation Agreement and Release, dated as of September 29, 2009 by and among Cano Petroleum, Inc., Resaca Exploitation, Inc. and S. Jeffrey Johnson, incorporated by reference from Exhibit 10.2 to Current Report on Form 8-K filed on October 1, 2009.
10.117+
Separation Agreement and Release, dated as of September 29, 2009 by and among Cano Petroleum, Inc., Resaca Exploitation, Inc. and Benjamin L. Daitch, incorporated by reference from Exhibit 10.3 to Current Report on Form 8-K filed on October 1, 2009.
10.118
Form of Stock Voting Agreement between Cano Petroleum, Inc. and certain holders of Series D Convertible Preferred Stock of Cano Petroleum, Inc., incorporated herein by reference to Exhibit 10.1 to Cano’s Current Report on Form 8-K filed with the SEC on October 21, 2009.
10.119+
Form of Stock Voting Agreement between Cano Petroleum, Inc. and S. Jeffrey Johnson, incorporated herein by reference to Exhibit 10.2 to Cano’s Current Report on Form 8-K filed with the SEC on October 21, 2009.
10.120
Amendment No. 1 and Agreement dated December 30, 2009 among Cano Petroleum, Inc., certain Guarantors, certain Lenders and Union Bank, N.A., incorporated herein by reference to Exhibit 10.1 to Cano’s Current Report on Form 8-K filed with the SEC on January 6, 2010.
10.121
Amendment No. 1 and Agreement dated December 30, 2009 among Cano Petroleum, Inc., certain Guarantors, certain Lenders and UnionBanCal Equities, Inc., incorporated herein by reference to Exhibit 10.2 to Cano’s Current Report on Form 8-K filed with the SEC on January 6, 2010.
10.122
Amendment No. 1 dated February 24, 2010 to Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Cano’s Current Report on Form 8-K filed on February 25, 2010.
10.123
Amendment No. 2 dated April 1, 2010 to Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Cano’s Current Report on Form 8-K filed on April 6, 2010.
10.124
Amendment No. 3 dated April 28, 2010 to Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Cano’s Current Report on Form 8-K filed on April 29, 2010.
10.125
Amendment No. 2 and Agreement dated March 30, 2010 among Cano, certain Guarantors, certain Lenders and Union Bank, N.A., incorporated herein by reference to Exhibit 10.1 to Cano’s Current Report on Form 8-K filed with the SEC on March 31, 2010.
10.126
Amendment No. 2 and Agreement dated March 30, 2009 among Cano, certain Guarantors, certain Lenders and UnionBanCal Equities, Inc., incorporated herein by reference to Exhibit 10.2 to Cano’s Current Report on Form 8-K filed with the SEC on March 31, 2010.
10.127
Investors Rights Agreement, dated April 5, 2010, by and among Resaca, Cano and the holders of Resaca preferred stock., incorporated herein by reference to Exhibit 10.2 to Cano’s Current Report on Form 8-K filed with the SEC on April 6, 2010.
10.128
Amendment No. 4 dated May 19, 2010 to Agreement and Plan of Merger, dated September 29, 2009 by and among Resaca Exploitation, Inc., Resaca Acquisition Sub, Inc. and Cano Petroleum, Inc., incorporated by reference from Exhibit 10.1 to Cano’s Current Report on Form 8-K filed on May 20, 2010.
12.1*
Ratio of Earnings to Fixed Charges.
21.1*
Subsidiaries of the Company.
23.1*
Consent of Hein & Associates LLP.
23.2*
Consent of Miller & Lents, Ltd., Independent Petroleum Engineers.
23.3*
Consent of Haas Engineering Services, 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.
99.1*
Report of Haas Petroleum Engineering Services, Inc.
* Filed herewith.
+ Management contract or compensatory plan, contract or arrangement.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Cano Petroleum, Inc.-Years Ended June 30, 2010, 2009 and 2008
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Cano Petroleum, Inc.
We have audited the consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries (collectively, the “Company”) as of June 30, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2010, in conformity with U.S. generally accepted accounting principles.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We were not engaged to examine management’s assessment of the effectiveness of Cano Petroleum, Inc.’s internal control over financial reporting as of June 30, 2010, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting and, accordingly, we do not express an opinion thereon.
HEIN & ASSOCIATES LLP
Dallas, Texas
September 22, 2010
CANO PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
In Thousands, Except Shares and Per Share Amounts
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
In Thousands, Except Per Share Data
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Dollar Amounts in Thousands
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Dollar Amounts in Thousands
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
As of June 30, 2010, Cano Petroleum, Inc. (together with its direct and indirect wholly-owned subsidiaries, “Cano,” “we,” “us,” or the “Company”) is an independent crude oil and natural gas company based in Fort Worth, Texas. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery (“EOR”) techniques at a low cost. We intend to convert these proved undeveloped and/or unproved reserves into proved producing reserves by applying water, gas and/or chemical flooding and other EOR techniques. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma.
2. LIQUIDITY / GOING CONCERN
At June 30, 2010, we had cash and cash equivalents of $0.3 million. We had negative working capital of $66.9 million, which includes $66.5 million of long-term debt that was shown as a current liability. For the year ended June 30, 2010, we had cash flow used in operations of $0.2 million, which included $1.9 million of merger-related cash expenses.
On July 20, 2010, we terminated our announced merger with Resaca Exploitation, Inc. (“Resaca”) that had been initiated pursuant to an Agreement and Plan of Merger dated September 29, 2009. On July 26, 2010 we announced the engagement of Canaccord Genuity and Global Hunter Securities to assist our Board in a review of strategic alternatives, with a goal of maximizing economic value for our shareholders. The strategic alternatives we are considering include the sale of the Company, the sale of some or all of our existing oil and gas properties and assets, and potential business combinations.
We currently have limited access to capital. On August 6, 2010, we finalized Consent and Forbearance Agreements with the lenders under our credit agreements that waived potential covenant compliance issues for the periods ending June 30, 2010 and September 30, 2010, set certain deadlines for the execution of our strategic alternatives process and allowed us to sell certain natural gas commodity derivative contracts for cash proceeds of $0.8 million, which was intended to provide Cano sufficient liquidity to complete its strategic alternatives process. As discussed in Note 5 to our Consolidated Financial Statements, we currently have no available borrowing capacity under our senior and subordinated credit agreements.
The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred and our current negative working capital, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. The ability of the Company to continue as a going concern will be dependent upon the outcome of the strategic alternatives review. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation and Use of Estimates
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Cano and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect
reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved crude oil and natural gas reserves, which may affect the amount at which crude oil and natural gas properties are recorded. The computation of share-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. Our liabilities and assets associated with commodity derivatives involve significant assumptions related to volatility and future prices for crude oil and natural gas. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.
Cano’s Proved Reserves
The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices based on an unweighted 12-month average and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases. A decline in estimates of proved reserves may result from lower prices, new information obtained from development drilling and production history; mechanical problems on our wells; and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserves estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserves estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.
Oil and Gas Properties and Equipment
We follow the successful efforts method of accounting. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense. The costs of drilling and equipping exploratory wells are deferred until the Company has determined whether proved reserves have been found. If proved reserves are found, the deferred costs are capitalized as part of the wells and related equipment and facilities. If no proved reserves are found, the deferred costs are charged to expense. All development activity costs are capitalized. We are primarily engaged in the development and acquisition of crude oil and natural gas properties. Our activities are considered development where existing proved reserves are identified prior to commencement of the project and are considered exploration if there are no proved reserves at the beginning of such project. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisition and development activities and deferred exploratory drilling costs. Capitalized overhead costs that directly relate to our drilling and development activities were $0.8 million and $1.1 million for the years ended June 30, 2010 and 2009, respectively. We recorded capitalized interest costs of $2.0 million and $1.4 million for the years ended June 30, 2010 and 2009, respectively.
Costs for repairs and maintenance to sustain or increase production from existing producing reservoirs are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Depreciation and depletion of producing properties are computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Our unit-of-production amortization rates are revised prospectively on a quarterly basis based on updated engineering information for our proved developed reserves. Our development costs and lease and wellhead equipment are depleted based on
proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until impairment occurs. As of June 30, 2010 and 2009, capitalized costs related to waterflood and alkaline-surfactant-polymer (“ASP”) projects that were in process and not subject to depletion amounted to $51.6 million and $49.4 million, respectively, of which $0.0 million and $4.8 million, respectively, were deferred costs related to drilling and equipping exploratory wells associated with our ASP project, as discussed in Note 8.
If conditions indicate that long-term assets may be impaired, the carrying value of our properties is compared to management’s future estimated undiscounted net cash flow from the properties. If undiscounted cash flows are less than the carrying value, then the asset value is written down to fair value. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis. The impairment assessment is affected by factors such as the results of exploration and development activities, commodity price projections, remaining lease terms, and potential shifts in our business strategy.
Asset Retirement Obligation
Our financial statements reflect the fair value of our asset retirement obligation (“ARO”), which consists of future plugging and abandonment expenditures related to our oil and gas properties, that can be reasonably estimated, and discounted at our credit-adjusted risk-free rate. The asset retirement obligation is recorded as a liability at its estimated fair value at the asset’s inception, with an offsetting increase to producing properties on the consolidated balance sheets, which is depreciated such that the cost of the ARO is recognized over the useful life of the asset. Periodic accretion of the discount of the estimated liability to its expected settlement value is recorded as an expense in the consolidated statements of operations.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
Goodwill
The amount paid for certain acquisitions in excess of the fair value of the net assets acquired has been recorded as goodwill in the consolidated balance sheets. Goodwill is not amortized, but is assessed for impairment annually or whenever conditions would indicate impairment may exist. The goodwill impairment analysis is evaluated at the subsidiary level as part of the impairment analysis performed on oil and gas properties, as previously discussed.
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less. Excess cash funds are generally invested in U.S. government-backed securities. At times, we maintain deposit balances in excess of Federal Deposit Insurance Corporation insurance limits.
Accounts Receivable
Accounts receivable principally consist of crude oil and natural gas sales proceeds receivable and are typically collected within 35 days from the end of the month in which the related quantities are produced. We require no collateral for such receivables, nor do we charge interest on past due balances. We periodically review accounts receivable for collectability and reduce the carrying amount of the accounts receivable by an allowance. No such allowance was recorded at June 30, 2010 or 2009. As of June 30, 2010, our accounts receivable were primarily with independent purchasers of our crude oil and natural gas production. At June 30, 2010, we had balances due from three customers which were greater than 10% of
our accounts receivable related to crude oil and natural gas production. These three customers accounted for 42% (Valero Marketing Supply Co.), 19% (Coffeyville Resources Refinery and Marketing, LLC) and 18% (Plains Marketing, LP) of our accounts receivable, respectively.
At June 30, 2009, we had balances due from three customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These three customers accounted for 41% (Valero Marketing Supply Co.), 19% (Coffeyville Resources Refinery and Marketing, LLC), and 18% (Plains Marketing, LP) of our accounts receivable, respectively.
In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative purchasers with whom we could establish new relationships and replace one or more lost purchasers. We would not expect the loss of any single purchaser to have a long-term material adverse effect on our operations, though we may experience a short-term decrease in our revenues as we make arrangements for alternative purchasers. However, the loss of a single purchaser could potentially reduce the competition for our crude oil and natural gas production, which could negatively impact the prices we receive.
Revenue Recognition
Our revenue recognition is based on the sales method. We do not have imbalances for natural gas sales since we are primarily the 100% working interest owner in our properties. We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on publicly available information. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from the purchasers are collectible. The point of sale for our crude oil and natural gas production is at our applicable field tank batteries and gathering systems; therefore, we do not incur transportation costs related to our sales of crude oil and natural gas production.
As previously discussed, for the years ended June 30, 2010, 2009 and 2008, we sold our crude oil and natural gas production to several independent purchasers. The following table shows purchasers that accounted for 10% or more of our total operating revenues:
* Less than 10% of operating revenue
Oil and Gas Sales Payable
Our accounts receivable includes amounts that we collect from the purchasers of our crude oil and natural gas sales on behalf of us, and certain working interest and royalty owners. The portion of accounts receivable that pertains to us is recognized as operating revenue. The portion that pertains to certain working interest and royalty owners are included in oil and gas sales payable on our consolidated balance sheets.
Inventory
Our inventory consists of unsold barrels of crude oil remaining in our storage tanks at the end of the period. We value these crude oil barrels based on the lower of market or our average production cost.
Income Taxes
Deferred tax assets or liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities. These balances are measured using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. As of June 30, 2010, we have not recorded any accruals for uncertain tax positions. We are not involved in any examinations by the Internal Revenue Service. For Texas, Oklahoma, New Mexico and U.S. federal purposes, the review of our income tax returns is open for examination by the related taxing authorities for the tax years of 2004 through 2009.
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, 2010 and 2009. The carrying amounts for derivative assets and liabilities are based on mark-to-market valuations.
Net Income (Loss) per Common Share
Diluted net income (loss) per common share is computed in the same manner as basic net income (loss) per common share, but also considers the effect of shares of common stock underlying the following:
The shares of common stock underlying the stock options, Preferred Stock and PIK dividends, as shown in the preceding table, are not included in weighted average shares outstanding for the years ended June 30, 2010, 2009 or 2008 as their effects would be anti-dilutive.
Share-Based Compensation Expense
We account for share-based payment arrangements with employees and directors at their grant-date fair value and record the related expense over their respective service periods. The value of share-based compensation is impacted by our stock price, which has been highly volatile, and items that require management’s judgment, such as expected lives and forfeiture rates.
Derivatives
We are required to maintain commodity derivative contracts for a portion of our crude oil and natural gas production under our senior and subordinated credit agreements, as discussed in Note 5. The purpose of the derivatives is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect our cash flows which support our annual capital expenditure plans. We have entered into commodity derivatives that involve “costless collars and swaps” for our crude oil and natural gas sales. These derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets based upon their respective fair values. We have entered into an interest rate basis swap contract to reduce our exposure to future interest rate increases.
We do not designate our derivatives as cash flow or fair value hedges. We do not hold or issue derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparties to our commodity and interest rate swap derivatives. We anticipate, however, that our counterparties will be able to fully satisfy their respective obligations under our commodity and interest rate swap derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts nor are we required to post any collateral. We monitor the credit standing of our counterparties to understand our credit risk.
Changes in the fair values of our derivative instruments and cash flows resulting from the settlement of our derivative instruments are recorded in earnings as gains or losses on derivatives on our consolidated statements of operations.
Comprehensive Income
We had no elements of comprehensive income other than net loss for the years ended June 30, 2010, 2009 or 2008.
New Accounting Pronouncements
In March 2008, the FASB issued ASC 815 (formerly SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement 133). ASC 815 expands the required disclosures to discuss the uses of derivative instruments, the accounting for derivative instruments and related hedged items under ASC 815, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.
In June 2008, the FASB issued ASC 260 (formerly EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities). ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of earnings per share under the two-class method. Under ASC 260, share-based payment awards that contain nonforfeitable rights to dividends are “participating securities”, and therefore should be included in computing earnings per share using the two-class method. ASC 260 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 260 on July 1, 2009. The effect of adopting ASC 260 increased the number of shares used to compute our earnings per share; however, the adoption of ASC 260 did not have a material impact on our financial position, results of operations or cash flows.
In December 2008, the FASB issued ASC 815 (formerly EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock). ASC 815 affects companies that have provisions in their securities purchase agreements (e.g. convertible instruments) that provide for the reset of the current conversion price based upon new issuances by companies at prices below the current conversion price of said instrument. Securities purchase agreements with such provisions will require the embedded derivative instrument to be bifurcated and separately accounted for as a derivative. Subject to certain exceptions, our preferred stock provides for resetting the conversion price if we issue new common stock below $5.75 per share. ASC 815 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We adopted ASC 815 on July 1, 2009. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows as the reset conversion provision did not meet the definition of a derivative since it was not readily net-cash settled.
On December 31, 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for
determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserve preparer or auditor and file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit. The new rules also require that oil and gas reserves be reported using a twelve-month average price rather than period-end prices. The new rules are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. Additionally, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosures, as set forth in ASU No. 2010-03, Extractive Activities-Oil and Gas (Topic 932), to align with the requirements of the SEC’s revised rules. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.
In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820). ASU 2010-06 Subtopic 820-10 provides new guidance on improving disclosures about fair value measurements. The new standard requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement. Specifically, the new standard will now require: (a) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for transfers and (b) in the reconciliation for fair value measurements using significant unoberservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, the new standard clarifies the requirements of the following existing disclosures: (a) for purposes of reporting fair value measurements for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities and (b) a reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The adoption of the requirements of this standard in the quarter ended March 31, 2010 did not have a material impact on our financial position or results of operations.
4. PREFERRED STOCK
On September 6, 2006, we sold $49.1 million of Preferred Stock. We were required to file a registration statement on Form S-1 with the Securities and Exchange Commission (the “SEC”) registering the resale of the common shares underlying the Preferred Stock, which was filed on October 13, 2006 and was declared effective on January 4, 2007. On April 9, 2007, we also filed to register these same common shares on a registration statement on Form S-3, which was declared effective on April 19, 2007. We are required to maintain the effectiveness of the registration statement until such common shares may be resold pursuant to Rule 144 under the Securities Act of 1933, as amended, or all such common shares have been resold 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 from the September 2006 offering. We do not believe it is probable we will incur any penalties under this provision and accordingly have not accrued any loss.
The Preferred Stock has a 7.875% dividend and features a paid-in-kind (“PIK”) provision that allows the investor, at its option, to receive additional shares of common stock upon conversion for the dividend in lieu of a cash dividend payment. Once the investor has chosen the PIK or cash distribution option, all future distributions follow the same choice. As of June 30, 2009, approximately 59% of the Preferred Stock dividends were PIK. The Preferred Stock is convertible at the holder’s option to common stock at a price of $5.75 per share. If any Preferred Stock remains outstanding on September 6, 2011, we are required to redeem the Preferred Stock for a redemption amount in cash equal to the stated value of the Preferred Stock, plus accrued dividends and PIK dividends. The issuance of Preferred Stock is accounted for as temporary equity since the holder can request redemption for cash under certain circumstances.
Pursuant to the terms of the Preferred Stock and subject to certain exceptions, if we issue or sell common stock at a price less than the conversion price (currently $5.75 per share) in effect immediately prior to such issuance or sale, the conversion price shall be reduced. If such an issuance is made, the conversion price will be lowered to the weighted average price of (x) the total common shares outstanding prior to said issuance multiplied by $5.75 and (y) the new shares issued at the new issuance price. The above described adjustment is not triggered by issuances or sales involving the following: (i) shares issued in connection with an employee benefit plan; (ii) shares issued upon conversion of our Preferred Stock; (iii) shares issued in connection with a firm commitment underwritten public offering with gross proceeds in excess of $50,000,000; (iv) shares issued in connection with any strategic acquisition or transaction; (v) shares issued in connection with any options or convertible securities that were outstanding on August 25, 2006; or (vi) shares issued in connection with any stock split, stock dividend, recapitalization or similar transaction.
Each holder of Preferred Stock is entitled to the whole number of votes equal to the number of shares of common stock issuable upon conversion. The Preferred Stock shall vote as a class with the holders of the common stock as if they were a single class of securities upon any matter submitted to the vote of the stockholders except those matters required by law or the terms of the Preferred Stock to be submitted to a class vote of the holders of the Preferred Stock, in which case the holders of the Preferred Stock only shall vote as a separate class.
Upon a voluntary or involuntary liquidation, dissolution or winding up of Cano or such subsidiaries of Cano the assets of which constitute all or substantially all of the assets of the business of Cano and its subsidiaries taken as a whole, the holders of our Preferred Stock shall be entitled to receive an amount per share equal to $1,000 plus dividends owed on such share prior to any payments being made to any class of capital stock ranking junior on liquidation to the Preferred Stock.
At June 30, 2010, 28,100 shares of Series D Convertible Preferred Stock were outstanding (including 4,251 shares from PIK dividends). At June 30, 2009, 26,987 shares of Series D Convertible Preferred Stock were outstanding (including 3,138 shares from PIK dividends). During November and December 2008, we repurchased 22,948 shares of Series D Convertible Preferred Stock, including accrued dividends and 2,323 shares from PIK dividends for approximately $10.4 million, realizing a gain of $10.9 million.
For the year ended June 30, 2010, the preferred dividend was $1.8 million, of which $1.1 million were PIK dividends. For the year ended June 30, 2009, the preferred dividend was $2.7 million, of which $1.6 million were PIK dividends.
At June 30, 2010, the Preferred Stock and cumulative PIK dividends were convertible into 4,147,652 and 739,347 shares, respectively, of our common stock at a conversion price of $5.75 per share.
On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.
5. DEBT
At June 30, 2010 and 2009, the outstanding amount due under our credit agreements was $66.5 million and $55.7 million, respectively. The $66.5 million at June 30, 2010, consisted of outstanding borrowings under the amended and restated credit agreement (the “ARCA”) and subordinated credit agreement (the “SCA”) of $51.5 million and $15.0 million, respectively. At June 30, 2010, the average interest rates under the ARCA and SCA were 2.85% and 6.54%, respectively.
Forbearance Agreements
On August 5, 2010, we executed a Consent and Forbearance Agreement (the “Senior Forbearance Agreement”) with Natixis and Union Bank, N.A. (“UBNA”), relating to existing and potential defaults under the ARCA dated December 17, 2008 among Cano, Natixis and UBNA and a Consent and Forbearance Agreement (together with the Senior Forbearance Agreement, the “Forbearance Agreements”) with UnionBanCal Equities, Inc. (“UBE”), relating to existing defaults under the SCA dated December 17, 2008 between Cano and UBE (as amended, the SCA and together with the ARCA, the “Credit Agreements”). Pursuant to the Forbearance Agreements, Natixis, UBNA and UBE agreed to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of the following defaults (the “Designated Defaults”):
· Cano’s failure to pay the amendment fees required by Amendment No. 2 to each of the Credit Agreements;
· Cano’s failure to provide an Internal Engineering Report and accompanying officer’s certificate on or before March 30, 2010, as required by the Credit Agreements;
· Cano’s potentially prohibited cash payments with respect to its shares of Preferred Stock on June 29, 2010 and June 30, 2010; and
· Cano’s failure to comply with certain financial covenants contained in the Credit Agreements for the quarter ended June 30, 2010 and potential failure to comply with such covenants for the quarter ended September 30, 2010.
The Forbearance Agreements also contain the following material terms:
· Natixis, UBNA and UBE consent to Cano’s termination of certain natural gas hedge contracts.
· Cano may not make any indirect or direct cash payment, cash dividend or cash distribution in respect of its shares of Preferred Stock.
· Natixis, UBNA and UBE agree to forbear from exercising certain rights and remedies under the Credit Agreements arising as a result of Cano’s potential failure to pay interest upon receipt of a default notice on the unpaid principal amount of each advance under the SCA on September 30, 2010.
· Cano must establish, on or before August 10, 2010, an electronic data room with information available to persons that may be interested in consummating an asset purchase, merger, combination, refinancing, recapitalization or other similar transaction with Cano (each, a “Prospective Transaction”).
· Cano must execute, on or before September 15, 2010, a letter of intent evidencing the parties’ intent to consummate a Prospective Transaction that will close on or before October 29, 2010 (the “Definitive Transaction”).
· Cano must execute definitive documentation providing for a Definitive Transaction on or before September 30, 2010.
· Cano must close a Definitive Transaction on or before October 29, 2010.
· Cano must deliver to UBNA and UBE a weekly written report of the parties visiting the electronic data room and a summary of progress and correspondence with respect to any Prospective Transaction.
· Cano must pay a forbearance fee in an amount equal to 1% of the aggregate principal amount of the advances outstanding under the Credit Agreements as of August 5, 2010 and the amendment fees required by Amendment No. 2 to each of the Credit Agreements upon receipt of proceeds from a Definitive Transaction.
· The aggregate commitments of Natixis and UBNA to lend to Cano pursuant to the ARCA are permanently reduced to $51.5 million, the current amount outstanding.
· UBNA and UBE shall not redetermine Cano’s borrowing bases under the Credit Agreements at any time prior to the termination of the Forbearance Agreements.
The Forbearance Agreements will terminate on the earlier of October 29, 2010, the date of Cano’s failure to comply with any of the terms described above and the date of the occurrence or existence of any default under either Credit Agreement, other than the Designated Defaults.
Regarding our compliance with the material items of the Forbearance Agreements:
· Prior to August 10, 2010, we did establish an electronic data room with information available to persons interested in consummating a Proposed Transaction.
· On August 10, 2010, we sold certain natural gas commodity derivative contracts to our counterparty, UBNA, for $0.8 million.
· At September 15, 2010, we were in discussions with parties regarding potential transaction structures and did not deliver a letter of intent pursuant to the Forbearance Agreements as discussed above. We continue to work with potential parties and our lenders on transaction structures.
The ARCA and SCA are discussed in greater detail below.
ARCA
On December 17, 2008, we finalized a new $120.0 million Amended and Restated Credit Agreement (the “ARCA”) with UBNA and Natixis. UBNA is the Administrative Agent and Issuing Lender of the ARCA. The current amount outstanding under the ARCA is equal to the commitment of $51.5 million. Per the terms of the Forbearance Agreement, the ARCA’s borrowing base shall not be redetermined.
Based upon the terms of the Forbearance Agreement, our interest rate is the sum of the one, two or three month LIBOR rate and 2.75%. As of the Forbearance Agreement, there will not be a commitment fee and we are deemed fully borrowed.
Unless specific events of default occur, the maturity date of the ARCA is December 17, 2012. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.
The ARCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain
payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBNA, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBNA, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.
SCA
On December 17, 2008, we finalized a $25.0 million SCA among Cano and UBE, as the Administrative Agent. On March 17, 2009, we borrowed the maximum available amount of $15.0 million under this agreement.
The interest rate is the sum of (a) the one, two or three month LIBOR rate (at our option) and (b) 6.0%. Through March 17, 2009, we owed a commitment fee of 1.0% on the unborrowed portion of the available borrowing amount. We no longer have a commitment fee since we borrowed the full $15.0 million available amount.
Unless specific events of default occur, the maturity date is June 17, 2013. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, material breaches of representations and warranties, breaches of covenants, certain cross-defaults, insolvency, a change in control or a material adverse change as defined in the SCA. Unless we are able to successfully execute one of our strategic alternatives, restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is unlikely that we will be able to meet our obligations as they become due and to continue as a going concern.
The SCA contains certain negative covenants including, subject to certain exceptions, covenants against the following: (i) incurring additional liens, (ii) incurring additional debt or issuing additional equity interests other than common equity interests of Cano; (iii) merging or consolidating or selling, leasing, transferring, assigning, farming-out, conveying or otherwise disposing of any property, (iv) making certain payments, including cash dividends to our common stockholders, (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or evidences of indebtedness or interest in any person or oil and gas properties or activities related to oil and gas properties unless (a) with regard to new oil and gas properties, such properties are mortgaged to UBE, as administrative agent, or (b) with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement or mortgage in favor of UBE, as administrative agent, and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm’s length transactions.
6. DERIVATIVES
Our derivatives consist of commodity derivatives and an interest rate swap arrangement, which are discussed in greater detail below.
Commodity Derivatives
Pursuant to the ARCA and SCA discussed in Note 5, we are required to maintain our existing commodity derivative contracts. We entered into commodity derivative contracts to partially mitigate the risk associated with extreme fluctuations of prices for our crude oil and natural gas sales. We have no obligation to enter into commodity derivative contracts in the future. Should we choose to enter into commodity derivative contracts to mitigate future price risk, we cannot enter into contracts for greater than 85% of our crude oil and natural gas production volumes attributable to proved producing reserves for a
given month. As of June 30, 2010, we maintained the following “collar” commodity derivative contracts with UBNA as our counterparty, which is one of the senior lenders under the ARCA:
(a) This column is computed by dividing the “Mcf per Day” by 6 and adding it to “Barrels per Day.”
(b) As discussed in Note 2, on August 10, 2010, we sold certain natural gas commodity derivative contracts realizing net proceeds of $0.8 million pursuant to the Forbearance Agreement.
During October 2008, we sold certain uncovered “floor price” commodity derivative contracts for the period July 2010 to December 2010 for $0.6 million to our counterparty and realized a gain of $0.1 million. During November 2008, we sold all remaining uncovered “floor price” commodity derivative contracts for the period November 2008 through June 2010 for $2.6 million to our counterparty and realized a gain of $0.6 million.
On September 11, 2009, we entered into two fixed price commodity swap contracts with Natixis as our counterparty, which is one of our senior lenders under the ARCA. The fixed price swaps are based on West Texas Intermediate NYMEX prices and are summarized in the table below.
Interest Rate Swap Agreement
On January 12, 2009, we entered into a three-year LIBOR interest rate basis swap contract with Natixis Financial Products, Inc. (“Natixis FPI”) for $20.0 million in notional exposure. We entered into the interest rate swap agreement to partially mitigate the risk associated with rising interest rates. Under the terms of the transaction, we will pay Natixis FPI, in three-month intervals, a fixed rate of 1.73% and Natixis FPI will pay Cano the prevailing three-month LIBOR rate.
Financial Statement Impact
During the years ended June 30, 2010, 2009 and 2008, respectively, the gain (loss) on derivatives reported in our consolidated statements of operations is summarized as follows:
The realized gain (loss) on derivatives consists of actual cash settlements under our commodity collars and interest rate swap derivatives during the respective periods, and the sale of “floor price” commodity derivative contracts during October and November 2008. The cash settlements received/accrued by us under commodity derivatives were cumulative monthly payments due to us since the NYMEX natural gas and crude oil prices were lower than the floor prices set for the respective time periods and realized gains from the sale of uncovered “floor price” contracts as previously discussed. The cash settlements paid/accrued by us under commodity derivatives were cumulative monthly payments due to our counterparty since the NYMEX crude oil and natural gas prices were higher than the ceiling prices set for the respective time periods. The cash settlements paid/accrued by us under the interest rate swap were quarterly payments to our counterparty since the actual three-month LIBOR interest rate was lower than the fixed 1.73% rate we pay to the counterparty. The cash flows relating to the derivative instrument settlements that are due, but not cash settled are reflected in operating activities on our consolidated statements of cash flows as changes to current liabilities. At June 30, 2010, we had recorded a $0.3 million receivable from our counterparty included in accounts receivable on our consolidated balance sheet. At June 30, 2009, we had recorded a $0.6 million receivable from our counterparty included in accounts receivable on our consolidated balance sheet.
The unrealized gain (loss) on commodity derivatives represents estimated future settlements under our commodity derivatives and is based on mark-to-market valuation based on assumptions of forward prices, volatility and the time value of money as discussed below. We compared our internally derived valuation to our counterparties’ independently derived valuation to further validate our mark-to-market valuation.
The unrealized gain (loss) on interest rate swap represents estimated future settlements under our interest rate swap agreement and is based on a mark-to-market valuation based on assumptions of interest rates, volatility and the time value of money as discussed below.
Fair Value Measurements
Our assets and liabilities recorded at fair value are categorized based upon the level of judgment associated with the inputs used to measure their fair value. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to
unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
Level 1-Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2-Inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.
Level 3-Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The fair value of our derivative contracts are measured using Level 2 and Level 3 inputs. The Level 3 input pertained to the subjective valuation for the effect of our own credit risk, which was significant to the fair value of the crude oil swap derivative contracts. The fair value of our commodity derivative contracts and interest rate swap are measured using Level 2 inputs based on the hierarchies previously discussed.
The estimated fair value of derivatives included in the consolidated balance sheet at June 30, 2010 is summarized below.
At September 30, 2009, our net derivative asset was classified as Level 2 as the subjectivity of our valuation for the effect of our own credit risk was insignificant. At December 31, 2009, since the subjective valuation of our own credit risk is significant, we reclassified our derivative liabilities as Level 3. At June 30, 2010, we continue to classify our derivative liabilities as Level 3 as presented in the table below.
(a) Total realized and unrealized gains are included in gain (loss) on commodity derivatives in the consolidated statements of operations.
The following table shows the reconciliation of changes in the fair value of the net derivative assets classified as Level 2 and 3, respectively, in the fair value hierarchy for the year ended June 30, 2010 (in thousands).
The change from net derivative assets of $7.7 million at June 30, 2009 to net derivative assets of $1.2 million at June 30, 2010 is attributable to the increases in crude oil and natural gas futures prices. These amounts are based on our mark-to-market valuation of these derivatives at June 30, 2010 and may not be indicative of actual future cash settlements.
The following table summarizes the fair value of our derivative contracts as of the dates indicated:
7. DISCONTINUED OPERATIONS
On October 1, 2008, we completed the sale of our wholly-owned subsidiary, Pantwist, LLC, for a net purchase price of $40.0 million consisting of a $42.7 million purchase price adjusted for $2.1 million of net cash received from discontinued operations during the three months ended September 30, 2008 and $0.6 million of advisory fees. The sale had an effective date of July 1, 2008.
On December 2, 2008, we completed the sale of our Corsicana oil and gas properties (the “Corsicana Properties”) for $0.3 million. In the three-month period ended September 30, 2008, we recorded a $3.5 million ($2.3 million after-tax) impairment of the Corsicana Properties, as we determined that we would not be developing its proved undeveloped reserves within the next five years.
On January 27, 2010, we completed the sale of our interests in certain oil and gas properties located in the Texas Panhandle (“Certain Panhandle Properties”) for net proceeds of $6.2 million, subject to customary post-closing adjustments. The sale had an effective date of January 1, 2010.
The operating results of Pantwist, LLC, the Corsicana Properties and the Certain Panhandle Properties for the years ended June 30, 2010, 2009 and 2008 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below (in thousands).
Interest expense, net of interest income, was allocated to discontinued operations based on the percent of operating revenues applicable to discontinued operations to the total operating revenues.
At June 30, 2009, on our consolidated balance sheet, the assets relating to the Certain Panhandle Properties are classified as assets held for sale and the liabilities are classified as liabilities associated with discontinued operations.
8. COSTS INCURRED FOR DRILLING AND EQUIPPING EXPLORATORY WELLS USING SECONDARY AND TERTIARY TECHNOLOGY
As part of our growth strategy, we incur costs associated with secondary and tertiary techniques that involve drilling and equipping exploratory wells. This occurs within reservoirs for which we already have proved developed reserves recorded from existing primary or secondary development; however, there are no proved reserves for subsequent secondary or tertiary activities. Secondary and tertiary costs for drilling and equipping wells include converting primary production wells to injection wells, installation of injection facilities, and injecting materials. When conducting secondary and tertiary drilling and equipping activities, we defer drilling and equipping costs associated with these exploratory wells pending a determination of whether proved reserves are found. If proved reserves are not found, all of the costs associated with the project are recorded as exploration expense in the period in which such determination is made. If proved reserves are found, the drilling and equipping costs incurred in the project are added to the depletion base and depreciated using the units of production method based over the production life of the associated proved developed reserves.
Secondary and tertiary projects typically take longer to complete than drilling primary production wells, and as a result, the period during which exploratory drilling costs are deferred is longer. Our secondary and tertiary projects are evaluated to determine whether they have found proved reserves when the project is substantially complete. We consider a secondary or tertiary project to be substantially
complete when the amount of material injected reaches our target pore volume injection (“PVI”) percentage determined necessary to stimulate response. This applied to two projects - the Duke Sand waterflood at our Desdemona Properties and the ASP chemical injection pilot project at the Nowata Properties (“Nowata ASP Project”). These two projects are updated as follows.
Duke Sand Waterflood. The primary source of water for this waterflood project was derived from our Barnett Shale production. During July 2009, we shut-in our Barnett Shale natural gas production due to uneconomic natural gas commodity prices; therefore, we no longer have an economic source of water to continue flooding the Duke Sand. This reduced our rate of water injection to a point where we could not consider the waterflood to be active. We recorded exploration expense of $11.4 million for the year ended June 30, 2009.
Nowata ASP Project. December 2009, we finalized our performance analysis, which indicated the Nowata ASP Project did not result in significantly increased oil production quantities and is therefore considered not economically viable. Accordingly, at December 31, 2009, we recorded a $5.0 million pre-tax exploration expense.
For the years ended June 30, 2010, 2009 and 2008, we did not incur geological and geophysical expenses or delay rentals associated with exploration projects.
The table below summarizes the drilling and equipping costs incurred and deferred related to secondary and tertiary projects that were pending the determination of whether proved reserves have been found.
The following table provides an aging of deferred exploratory well costs based on the date the project was initiated (prior to determination of success).
The following table reflects the net change in deferred exploratory project costs:
9. STOCK OPTIONS
Our 2005 Long-Term Incentive Plan (the “2005 LTIP”), as approved by our stockholders, authorized the issuance of up to 3,500,000 shares of our common stock to key employees, consultants and outside directors of our company and subsidiaries. The 2005 LTIP stipulates that for any calendar year (i) the maximum number of stock options or stock appreciation rights that any Executive Officer (as defined in the Plan) can receive is 300,000 shares of common stock, (ii) the maximum number of shares relating to restricted stock, restricted stock units, performance awards or other awards that are subject to the attainment of performance goals that any Executive Officer can receive is 300,000 shares of common stock; and (iii) the maximum number of shares relating to all awards that an Executive Officer can receive is 300,000 shares. The 2005 LTIP permits the grant of incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, dividend equivalent rights and other awards, whether granted singly, in combination or in tandem. The 2005 LTIP terminates on December 7, 2015; however, awards granted before that date will continue to be effective in accordance with their terms and conditions.
Stock option awards are generally granted with an exercise price equal to our market price at the date of grant and have 10-year contractual terms. Stock option awards to employees generally vest over three years of continuous service. Stock option awards to directors generally vest immediately or in one year. On June 28, 2007, we resolved that upon the resignation of any current member of the Board of Directors who is in good standing on the date of resignation, such member’s unvested stock options shall be vested and shall have the exercise period for all options extended to twenty-four months after the date of resignation. The grant-date fair value of director options for which vesting was accelerated during the year ended June 30, 2008 amounted to approximately $31,000. Such amount is included in general and administrative expense on our consolidated statements of operations. There were no options for which vesting was accelerated during the years ended June 30, 2010 or 2009.
A summary of options we granted during the years ended June 30, 2010, 2009 and 2008 are as follows:
The following is a summary of stock options outstanding at June 30, 2010:
Based on our $0.77 stock price at June 30, 2010, the intrinsic value of both the options outstanding and exercisable options was $0.1 million.
Total options exercisable at June 30, 2010 amounted to 1,142,995 shares and had a weighted average exercise price of $4.19. Upon exercise, we issue the full amount of shares exercisable pursuant to the terms of the options from new shares. We have no plans to repurchase those shares in the future.
The following is a summary of options exercisable at June 30, 2010, 2009 and 2008:
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 estimated to be outstanding. The risk-free interest rate for periods within the contractual life of the option is based on the five-year U.S. Treasury yield curve in effect at the time of the respective grant. The expected dividend yield reflects our intent not to pay dividends on our common stock during the contractual periods.
The factors used to calculate the fair values of those options are summarized in the table below:
For the years ended June 30, 2010, 2009 and 2008, we have recorded a charge to stock compensation expense of $0.2 million, $0.7 million and $1.2 million, respectively, for the estimated fair value of the options granted to our directors and employees. As of June 30, 2010, total compensation cost related to non-vested option awards not yet recognized was insignificant.
10. DEFERRED COMPENSATION
We have granted share awards to key employees from our 2005 LTIP, previously discussed in Note 9. On July 2, 2007, we granted our executive officers share awards for services provided during the year ended June 30, 2007 totaling 395,000 shares vesting in three equal amounts on the first, second and third anniversaries of July 2, 2007.
On May 12, 2008, we granted our executive officers share awards for services provided during the year ended June 30, 2008 totaling 460,000 shares vesting in three equal amounts on the first, second and third anniversaries of May 12, 2008. On June 23, 2008, in connection with his hiring, we granted an executive officer share awards totaling 100,000 shares vesting in three equal amounts on the first, second and third anniversaries of June 23, 2008.
A summary of non-vested share awards for the three years ended June 30, 2010, 2009 and 2008 is as follows:
The 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 of the grants is based on our
actual stock price on the date of grant multiplied by the number of restricted shares granted. As of June 30, 2010, the value of non-vested share awards amounted to $1.2 million. For the years ended June 30, 2010, 2009 and 2008, we have recorded share-based compensation of $0.8 million, $2.4 million and $1.7 million, respectively, in general and administrative expense based on amortizing the fair value over the requisite service period.
11. RELATED PARTY TRANSACTIONS
S. Jeffrey Johnson, our Chief Executive Officer and Chairman of our board of directors, owns approximately 3.7% of our outstanding Preferred Stock. For the years ended June 30, 2010, 2009 and 2008, we paid preferred dividend payments to Mr. Johnson of approximately $79,000, $20,000 and $0, respectively. On August 5, 2010, we entered into Consent and Forbearance Agreements with the lenders under our credit agreements that prohibit us from making any indirect or direct cash payment, cash dividend or cash distribution in respect of our shares of Series D Convertible Preferred Stock.
Pursuant to an agreement dated December 16, 2004, as amended, we agreed with R.C. Boyd Enterprises, a Delaware corporation, to become the lead sponsor of a television production called Honey Hole (“Honey Hole Production”). As part of our sponsorship, we provided fishing and outdoor opportunities for children with cancer, children from abusive family situations and children of military veterans. We were entitled to receive two thirty-second commercials during all broadcasts of the Honey Hole Production and received opening and closing credits on each episode. Randall Boyd is the sole shareholder of R.C. Boyd Enterprises and is a member of our Board of Directors. Pursuant to an agreement dated as of December 5, 2007, as of December 31, 2008, we are no longer a Honey Hole Production sponsor. We paid no money to R.C. Boyd Enterprises after December 31, 2008. During the years ended June 30, 2010, 2009 and 2008, we paid $0, $75,000 and $150,000, respectively, for sponsorship activities.
12. IMPAIRMENT OF LONG-LIVED ASSETS AND GOODWILL
During the three-month period ended December 31, 2009, we wrote down $0.3 million of costs associated with the ASP facility used for the Nowata ASP Project. The facility’s water filtering process did not work properly with the oil-water fluid production at our Nowata Properties. We intend to use the ASP facility for future pilot tertiary projects at our Cato and Panhandle Properties.
During the three-month period ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale natural gas properties (“Barnett Shale Properties”) and a $0.7 million pre-tax impairment to the goodwill associated with our subsidiary which holds the equity in our Barnett Shale Properties. We recorded the impairments due to the decline in commodity prices which created an uncertainty in the likelihood of developing reserves associated with our Barnett Shale Properties within the next five years. During the three- month period ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline.
During the quarter ended September 30, 2008, we recorded a $3.5 million pre-tax impairment on our Corsicana Properties as it became unlikely that we would develop this asset within the next five years. During the quarter ended December 31, 2008, this $3.5 million charge was reclassified as part of income from discontinued operations as shown on our consolidated statements of operations. As previously discussed in Note 7, on December 2, 2008, we sold our interest in the Corsicana Properties for $0.3 million.
The fair values for our Barnett Shale and Corsicana Properties were determined using estimates of future net cash flows, discounted to a present value, which are considered “Level 3” inputs as previously discussed in Note 6.
13. ASSET RETIREMENT OBLIGATION
Our asset retirement obligation (“ARO”) primarily represents the estimated present value of the amount we will incur to plug and abandon our producing properties at the end of their productive lives, in
accordance with applicable state laws. We determine our ARO by calculating the present value of estimated cash flows related to the liability. At June 30, 2010, our liability for ARO was $3.2 million, of which $3.0 million was considered long term. At June 30, 2009, our liability for ARO was $2.9 million, of which $2.8 was considered long term. Our ARO is recorded as current or non-current liabilities based on the estimated timing of the related cash flows. For the years ended June 30, 2010, 2009 and 2008, we have recognized accretion expense, net of discontinued operations, of $0.3 million, $0.3 million and $0.1 million, respectively.
The valuation technique we utilize to determine the fair value of the liability at inception applies a credit-adjusted risk-free rate, which takes into account our credit risk, the time value of money, and the current economic state, to the undiscounted expected plugging and abandonment cash flows. Given the unobservable nature of certain inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs, as previously discussed in Note 6.
The following table describes the changes in our ARO for the years ended June 30, 2010 and 2009 (in thousands):
For the years ended June 10, 2010 and 2009, the change in estimate of our ARO liability resulted primarily from a change in estimated timing to plug and abandon wells.
14. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax provisions. Our income tax expense (benefit) is as follows:
A reconciliation of the differences between our applicable statutory tax rate and our effective income tax rate for the years ended June 30, 2010, 2009 and 2008 is as follows:
A schedule showing the significant components of the net deferred tax liability as of June 30, 2010 and 2009 are as follows:
At June 30, 2010 and 2009, we had net operating loss (“NOL”) carryforwards for tax purposes of approximately $84.6 million and $49.0 million, respectively. The net operating losses principally expire between 2024 and 2030. $2.2 million of these NOL carryforwards will be unavailable to offset any future taxable income due to limitations from change in ownership, which occurred at our merger in May 2004, as defined in Section 382 of the Internal Revenue Service code. The tax effect of this limitation is recorded as a valuation allowance of $770,000 at both June 30, 2010 and 2009.
15. COMMITMENTS AND CONTINGENCIES
Burnett Case
On March 23, 2006, the following lawsuit was filed in the 100th Judicial District Court in Carson County, Texas: Cause No. 9840, The Tom L. and Anne Burnett Trust, by Anne Burnett Windfohr, Windi Phillips, Ben Fortson, Jr., George Beggs, III and Ed Hudson, Jr. as Co-Trustees; Anne Burnett Windfohr;
and Burnett Ranches, Ltd. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and natural gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas.
The plaintiffs (i) allege negligence and gross negligence and (ii) seek damages, including, but not limited to, damages for damage to their land and livestock, certain expenses related to fighting the fire and certain remedial expenses totaling approximately $1.7 million to $1.8 million. In addition, the plaintiffs seek (i) termination of certain oil and natural gas leases, (ii) reimbursement for their attorney’s fees (in the amount of at least $549,000) and (iii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. The owner of the remainder of the mineral estate, Texas Christian University, intervened in the suit on August 18, 2006, joining Plaintiffs’ request to terminate certain oil and gas leases. On June 21, 2007, the judge of the 100th Judicial District Court issued a Final Judgment (a) granting motions for summary judgment in favor of Cano and certain of its subsidiaries on plaintiffs’ claims for (i) breach of contract/termination of an oil and gas lease; and (ii) negligence; and (b) granting the plaintiffs’ no-evidence motion for summary judgment on contributory negligence, assumption of risk, repudiation and estoppel affirmative defenses asserted by Cano and certain of its subsidiaries.
The Final Judgment was appealed and a decision was reached on March 11, 2009, as the Court of Appeals for the Tenth District of Texas in Amarillo affirmed in part and reversed in part the ruling of the 100th Judicial District Court. The Court of Appeals (a) affirmed the trial court’s granting of summary judgment in Cano’s favor for breach of contract/termination of an oil and gas lease and (b) reversed the trial court’s granting of summary judgment in Cano’s favor on plaintiffs’ claims of Cano’s negligence. The Court of Appeals ordered the case remanded to the 100th Judicial District Court. On March 30, 2009, the plaintiffs filed a motion for rehearing with the Court of Appeals and requested a rehearing on the affirmance of the trial court’s holding on the plaintiffs’ breach of contract/termination of an oil and gas lease claim. On June 30, 2009, the Court of Appeals ruled to deny the plaintiff’s motion for rehearing. On August 17, 2009 we filed an appeal with the Texas Supreme Court to request the reversal of the Court of Appeals ruling regarding our potential negligence. On December 11, 2009, the Texas Supreme Court declined to hear Cano’s appeal. Therefore, this case has been remanded to the district court for trial on the negligence claims and the trial date has been set for November 2, 2010.
Due to the inherent risk of litigation, the ultimate outcome of this case is uncertain and unpredictable. At this time, Cano management continues to believe that this lawsuit is without merit and will continue to vigorously defend itself and its subsidiaries, while seeking cost-effective solutions to resolve this lawsuit. Based on our knowledge and judgment of the facts as of September 22, 2010, we believe our financial statements present fairly the effect of the actual and the anticipated future costs to resolve this matter as of June 30, 2010.
There is no remaining insurance coverage for any claims associated with this fire litigation.
Securities Litigation against Outside Directors
On October 2, 2008, a lawsuit (08 CV 8462) was filed in the United States District Court for the Southern District of New York, against David W. Wehlmann; Gerald W. Haddock; Randall Boyd; Donald W. Niemiec; Robert L. Gaudin; William O. Powell, III and the underwriters of the June 26, 2008 public offering of Cano common stock (“Secondary Offering”) alleging violations of the federal securities laws. Messrs. Wehlmann, Haddock, Boyd, Niemiec, Gaudin and Powell were Cano outside directors on June 26, 2008. At the defendants’ request, the case was transferred to the United States District Court for the Northern District of Texas.
On July 2, 2009, the plaintiffs filed an amended complaint that added as defendants Cano, Cano’s Chief Executive Officer and Chairman of the Board, Jeff Johnson, Cano’s former Senior Vice President and Chief Financial Officer, Morris B. “Sam” Smith, Cano’s current Senior Vice President and Chief Financial Officer, Ben Daitch, Cano’s Vice President and Principal Accounting Officer, Michael Ricketts
and Cano’s former Senior Vice President of Engineering and Operations, Patrick McKinney, and dismissed Gerald W. Haddock, a former director of Cano, as a defendant. The amended complaint alleges that the prospectus for the Secondary Offering contained statements regarding Cano’s proved reserve amounts and standards that were materially false and overstated Cano’s proved reserves. The plaintiff is seeking to certify the lawsuit as a class action lawsuit and is seeking an unspecified amount of damages. On July 27, 2009, the defendants moved to dismiss the lawsuit. On December 3, 2009, the U.S. District Court for the Northern District of Texas granted motions to dismiss all claims brought by the plaintiffs. On December 18, 2009, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. On April 5, 2010, Cano filed its appellate brief to support its position. On April 19, 2010, the plaintiffs filed their response brief. On August 4, 2010, the U.S. Court of Appeals for the Fifth Circuit affirmed the dismissal by the U.S. District Court for the Northern District of Texas of all claims by the plaintiffs. By affirming the decision of the lower court, the U.S. Court of Appeals for the Fifth Circuit agreed that the plaintiff’s complaint failed to state a claim upon which relief could be granted, and thus found merit in dismissing the lawsuit. Due to the inherent risk of litigation, the outcome of this lawsuit is uncertain and unpredictable; however, Cano, its officers and its outside directors intend to continue to vigorously defend the lawsuit.
Cano is cooperating with its directors and officers liability insurance carrier regarding the defense of the lawsuit. We believe that the potential amount of losses resulting from this lawsuit in the future, if any, will not exceed the policy limits of Cano’s directors’ and officers’ liability insurance.
Other
Occasionally, we are involved in other various claims and lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management does not believe that the ultimate resolution of any current matters that are not set forth above will have a material effect on our financial position or results of operations. Management’s position is supported, in part, by the existence of insurance coverage, indemnification and escrow accounts. None of our directors, officers or affiliates, owners of record or beneficial owners of more than five percent of any class of our voting securities, or security holder is involved in a proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.
Section 7.6 of the Merger Agreement with Resaca provided for the Company and Resaca to share transaction expenses related to the printing, filing and mailing of the registration statement, the proxy/prospectus, and the solicitation of stockholder approvals. On September 2, 2010, we filed an action against Resaca in the Tarrant County District Court seeking a declaratory judgment to clarify the scope and determine the amount of any expenses that are reimbursable under Section 7.6 of the Merger Agreement.
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
Effective June 1, 2009, we entered into a non-cancelable operating lease for our principal executive offices in Fort Worth, Texas. The lease expires on May 31, 2014. In addition, during October 2005 we entered into a five-year operating lease for our field offices in Pampa, Texas expiring on October 1, 2010. We have also contracted for various equipment rentals at our field locations. Our remaining obligation for the life of our operating leases is $2.6 million. Future minimum rentals due under our non-cancellable operating leases were as follows on June 30, 2010:
Rent expense amounted to $0.7 million, $0.3 million, and $0.4 million for the years ended June 30, 2010, 2009 and 2008, respectively.
Employment Contracts
We have employment contracts with our executives that specify annual compensation, and provide for potential payments up to three times the annual salary and bonuses and immediate vesting of unexercised stock options and restricted stock under termination or change in control circumstances. The annual salaries and contract termination dates for each executive are as follows:
16. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
All of our operations are directly related to oil and natural gas producing activities located in Texas, Oklahoma and New Mexico.
Capitalized Costs Relating to Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Producing Activities
Proved Reserves Methodology
Our estimated proved reserves, as of June 30, 2010, include the effect of the SEC’s revised oil and gas rules, “Modernization of Oil and Gas Reporting,” issued in December 2008, which is effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. The revised SEC rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources
in reserves, the use of new technology for determining reserves and permitted disclosure of probable and possible reserves. In accordance with the SEC’s revised oil and gas rules, prior period reserves were not restated. The pricing used to estimate the reserves as of June 30, 2010 is based on an unweighted average first-day-of-the-month pricing for the past 12 fiscal months for crude oil and natural gas.
Our proved oil and natural gas reserves as of June 30, 2010 have been prepared by Haas Petroleum Engineering Services, Inc. (“Haas”), our independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at Haas meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards. Haas is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. For the years ended June 30, 2009 and 2008, our proved oil and natural gas reserves were prepared by Miller and Lents, LTD.
The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data, management review and review of the independent third party reserves report. Our reserve estimates are prepared in compliance with SEC rules, regulations and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Properties Information (Revision as of February 19, 2007) promulgated by the Society of Petroleum Engineers (“SPE Standards”). Our reserve reports are prepared by a registered independent engineering firm at the end of every year based on information provided by our Engineering and Operations Department. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, and more than five years of experience in reservoir engineering and is a member of the Society of Petroleum Engineers. Our senior management, including our Chief Executive Officer and Chief Financial Officer, reviews our reserves estimates before these estimates are finalized and disclosed in a public filing or presentation.
Our Engineering and Operations Department accumulates historical production data for our wells, calculates historical lease operating expenses and commodity price differentials, updates working interests and net revenue interests, obtains updated authorizations for expenditure and obtains logs, 3-D seismic and other geological and geophysical information. This data is forwarded to our registered independent engineering firm.
Proved Reserves (Unaudited)
The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The reserve data set forth in the reports of our registered independent engineering firms represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. Estimated quantities of net proved reserves and future net revenues are affected by oil and natural gas prices, which have fluctuated widely in recent years.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimated proved reserves may result from lower prices, adverse operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomic to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our crude oil and natural gas properties for impairment. Seventy-nine percent of our proved reserves are classified as proved undeveloped reserves. Capital expenditures forecasted in our reserve report amount to approximately $310.5million throughout the life of our proved reserves. Further, capital expenditures exceed our expected operating cash flows in our reserve report for the five-year period succeeding June 30, 2010. As we have done during each year of our existence, to develop our reserves as reported in our June 30, 2010 reserve report, we will require access to the capital markets and/or consider divestitures of oil and gas properties in each of the next five years, as our projected capital expenditures are greater than projected cash flow from operations through December 2015.
Our proved reserves are summarized in the table below.
The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the standard of “high degree of confidence” specified as a 90 percent recovery probability used in estimating proved reserves. The new SEC rules permit the Company to report probable and possible reserves, which are less certain than the 90 percent recovery probability applied to proved reserves. Our reserves report, as of June 30, 2010, as prepared by Haas identified undeveloped probable and possible reserves. Our undeveloped probable reserves totaled crude oil and natural gas reserves of 10,442 Mbbls and 23,519 MMcf, respectively. Our possible reserves totaled crude oil and natural gas reserves of 8,563 Mbbls and 5,968 MMcf, respectively.
Reserve estimates using the SEC revised rules approximated the reserves estimated under the previous SEC reporting requirements. Therefore, the impact to depletion and depreciation expense was minimal. Under the SEC revised rules, the standardized measure of discounted future net cash flows was approximately $15.0 million lower as compared to the previous SEC reporting requirements.
For the proved reserves as of June 30, 2010, the prices used to compute the crude oil and natural gas proved reserves represent the unweighted average first-day-of-the-month NYMEX crude oil and
natural prices for the past 12 fiscal months ended June 30, 2010 pursuant to the previously discussed SEC’s final rule, which amounted to $75.76 per barrel and $4.10 per MMBtu, respectively.
For the proved reserves as of June 30, 2009 and 2008, the base prices used to compute the crude oil and natural gas reserves represent the NYMEX oil and natural gas prices at June 30, 2009 and 2008. For the reserves at June 30, 2009, the crude oil and natural gas prices were $69.89 per barrel and $3.71 per MMbtu, respectively. For the reserves at June 30, 2008, the crude oil and natural gas prices were $140.00 per barrel and $13.15 per MMbtu, respectively.
Change in Reserves at June 30, 2010
Extensions and discoveries totaling 0.3 MMBOE resulted primarily from newly identified behind-pipe opportunities at our Cato and Panhandle Properties.
Sales of minerals in place resulted from the sale of certain wells in the Panhandle Properties as discussed in Note 7.
Revisions in previous quantity estimate resulted primarily from reduced PUD reserves at the Panhandle Properties of 4.4 MMBOE and reduced PDP reserves at the Cato Properties of 0.9 MMBOE.
Haas utilized the East Schafer Ranch waterflood as the analogy for assessing the PUD reserves for each lease of the Panhandle Properties. The East Shafer Ranch waterflood experienced a secondary recovery of 11% of the original oil in place, or OOIP, which equated to a secondary to primary ratio of 0.35. Haas, based solely on its professional experience and engineering judgment, determined that for the purpose of reporting the Panhandle Properties’ proved reserves, they would limit each of the Panhandle Properties’ waterflood recovery factors to a 0.35 secondary to primary ratio as a maximum, and not use a percentage of OOIP to determine proved reserves. In some cases, adjustments were made since the by lease production history appeared to have allocation issues. Haas’ decision to limit proved reserve recovery based upon a 0.35 secondary to primary ratio resulted in a proved reserve decrease of 3.1 MMBOE. Further, Haas looked at the delayed responses Cano has experienced at its Cockrell Ranch unit, along with reservoir conformance and permeability trends analyzed from core data, and decided to limit proved reserves to a 0.175 secondary to primary ratio for the Cockrell Ranch and the adjacent Pond Lease, resulting in a proved reserve decrease of 1.3 MMBOE. Haas determined that the reductions to the combined company’s proved reserves would be validly reclassified as probable reserves as proved reserves indicate a 90% likelihood that production will meet or exceed the booked value while probable reserves require a 50% confidence level to be so classified.
The reduction of PDP reserves at Cato Properties is a result of lower field production rates associated with lower water injection rates at the waterflood.
Change in Reserves at June 30, 2009
· The extensions and discoveries pertain to our drilling and completing wells, and results of the waterflood project in the San Andres formation at our Cato Properties.
· The sales of minerals in place pertain to our divestitures of oil and natural gas properties located in Texas as discussed in Note 7.
· The reduction for revisions of prior estimates pertain to the impairments of our Barnett Shale Properties (Note 12) of 2.3 MMBOE and other revisions of 1.4 MMBOE driven primarily from the decline in commodity prices and forecast changes which reduced the economic life of our assets, as compared to proved reserves as of June 30, 2008. The specific field changes are as follows:
· At the Desdemona Properties - Barnett Shale, production performance due to price accounted for 0.4 MMBOE of negative revisions in PDP, partially offset by a positive 0.1 MMBOE at the Desdemona Properties - Duke Sands projects due to improved recoveries.
· At the Davenport Properties, commodity price-related effects reduced PDP reserves by 0.2 MMBOE.
· At the Nowata Properties, improved recoveries increased PDP reserves by 0.1 MMBOE.
· At the Panhandle Properties, PDP reserves decreased 1.3 MMBOE largely as a result of transferring 0.7 MMBOE to PUD reserves, commodity price-related effects and production, which was partially offset by increased PUD reserves of 0.3 MMBOE-a net reduction of 1.0 MMBOE.
Change in Reserves at June 30, 2008
· The purchases of minerals in place pertain to our acquisitions of oil and natural gas properties located in the Texas Panhandle (“Panhandle Properties”).
· The extensions and discoveries pertain to our drilling and completing wells at the Cato Properties and the Panhandle Properties, and results of the waterflood project at the Panhandle Properties.
· The reduction for revisions of prior estimates primarily pertains to:
· For the Desdemona Properties-Barnett Shale, we considered the lower production performance from the existing wells and current industry practice that limited the number of horizontal offset PUD locations that could be booked against existing wells from eight to two locations. Therefore, PUD reserves were reduced by approximately 3.0 MMBOE due to lower performance results from the existing wells and further reduced by another 4.6 MMBOE as the number of PUD drilling locations decreased from 76 to 40. Also, as a result of production performance, PDP and PDNP reserves were decreased by 0.4 MMBOE.
· For the Panhandle Properties, we reclassified 5.6 MMBOE from PUD to probable reserves as there were insufficient analogs to the Granite Wash formation to justify PUD classification. In addition, we could not commit to developing the Granite Wash within five years.
· For the Pantwist Properties, based on current industry practice, we reclassified 4.4 MMBOE of PUD reserves to probable reserves as we could not commit to developing Pantwist’s PUD reserves within five years.
The reductions in crude oil and natural gas reserves were partially offset by a proved reserve increases of 4.4 MMBOE at the Cato Properties, where third-party engineering and geologic studies confirmed increases to original oil in place estimates and PUD reserves, and an infill drilling program resulted in an increase in PDP and PDNP reserves. There were also the following proved reserve increases for positive performance due to price increases: (i) at the Panhandle Properties, PDP reserves were increased by 0.2 MMBOE and (ii) at the Desdemona Properties PDNP reserves were increased by 0.3 MMBOE. We also transferred reserves of 0.4 MMBOE from PDNP to PDP at the Davenport Properties and reserves of 1.4 MMBOE from PUD to PDP at the Panhandle Properties.
Standardized Measure (Unaudited)
The standardized measure of discounted future net cash flows (“standardized measure”) and changes in such cash flows are prepared using assumptions including the use of year-end prices for oil and natural gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% annual discount rate.
Estimated well abandonment costs, net of salvage, are deducted from the standardized measure using year-end costs. Such abandonment costs are recorded as a liability on the consolidated balance sheets, using estimated values of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired.
The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.
Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves, proved undeveloped reserve additions attributable to increased development activity, reduced reserves due to lower performance from the existing wells, reduced reserves to comply with current industry practice that limited the number of PUD locations that could be booked against existing wells and lower reserves if a company is unable to commit to developing PUD reserves within five years.
Standardized Measure of Discounted Future Cash Flows (Unaudited)
The standardized measure of discounted estimated future net cash flows related to proved crude oil and natural gas reserves for the years ended June 30, 2010, 2009 and 2008 is as follows:
Changes in Standardized Measure of Discounted Future Cash Flows: (Unaudited)
The primary changes in the standardized measure of discounted estimated future net cash flows for the years ended June 30, 2010, 2009 and 2008 are as follows: