Item 1A. Risk Factors
Our business involves a high degree of risk. Investors should carefully consider the risks and uncertainties described below. Each of the following risks may materially and adversely affect our business, results of operations and financial condition. These risks may cause the market price of our common stock to decline, which may cause you to lose all or a part of the money you paid to buy our common stock.
Risks Related to Our Industry
Oil and natural gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the oil and natural gas we produce and sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Historically, the markets for oil and natural gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market and political uncertainty and other factors that are beyond our control, including:
•worldwide and domestic demands and supplies of oil and natural gas;
•weather conditions;
•the price and availability of alternative fuels;
•the availability of pipeline capacity;
•the price and level of foreign imports;
• domestic and foreign governmental regulations and taxes;
•the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•political instability or armed conflict in oil-producing regions; and
•the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves.
Government regulation may adversely affect our business and results of operations.
Oil and natural gas operations are subject to various and numerous federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, injection of substances, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations. The transportation and storage of refined products include the risk that refined products and other hydrocarbons may be
suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies and private parties for natural resources damages, personal injury, or property damages and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined and unrefined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. As a result, we may incur substantial expenditures and/or liabilities to third parties or governmental entities which could have a material adverse effect on us.
The oil and natural gas industry is capital intensive, and we may not be able to raise the capital needed in the future to conduct our operations as planned or make strategic acquisitions.
The oil and natural gas industry is capital intensive. We make substantial capital expenditures for the acquisition, exploration for and development of oil and natural gas reserves.
Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from bank borrowings and sales of our equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the level of oil and natural gas we are able to produce from existing wells;
•the prices at which oil and natural gas are sold; and
•our ability to acquire, locate and produce new reserves.
Any one of these variables can materially affect our ability to borrow under our credit agreements.
If our revenues or the borrowing base under our credit agreements 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 undertake or complete future drilling projects. We may, from time to time, seek additional financing, either in the form of increased bank borrowings, public or private sales of debt or equity securities or other forms of financing, or consider selling non-core assets to raise additional operating capital. However, we may not be able to obtain additional financing or make sales of non-core assets upon terms acceptable to us.
Risks Related to Our Business
Our limited history makes an evaluation of us and our future difficult and profits are not assured.
Prior to the Davenport Merger in May 2004, we were inactive with no significant operations. In connection with the Davenport Merger, we decided to focus our business on the acquisition of attractive crude oil and natural gas prospects, and the exploration, development and production of oil and natural gas on these prospects. Since that time, we have acquired rights in oil and natural gas properties and undertaken certain exploitation and other activities. However, we do not have a long operating history in our current business. We are in the process of initiating three waterfloods and an alkaline-surfactant project, and only have partially completed one of the waterfloods, with the other projects still being in progress. In view of our limited history in the oil and natural gas business, you may have difficulty in evaluating us and our business and prospects. You must consider our business and prospects in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. For our business plan to succeed, we must successfully undertake most of the following activities:
•find and acquire rights in strategic oil and natural gas properties;
•develop our oil and natural gas properties, including the successful application of EOR technologies and procedures, to the point at which oil and natural gas are being produced in commercially viable quantities;
•contract with third party service providers regarding services necessary to develop our oil and natural gas wells;
•contract with transporters and purchasers of our commercial production of oil and natural gas;
•maintain access to funds to pursue our capital-intensive business plan;
•comply with all applicable laws and regulations;
•implement and successfully execute our business strategy;
•respond to competitive developments and market changes; and
•attract, retain and motivate qualified personnel.
There can be no assurance that we will be successful in undertaking such activities. Our failure to undertake successfully most of the activities described above could materially and adversely affect our business, prospects, financial condition and results of operations. In addition, there can be no assurance that our exploitation and production activities will produce oil and natural gas in commercially viable quantities. There can be no assurance that sales of our oil and natural gas production will ever generate sufficient revenues or that we will be able to sustain profitability in any future period.
If we cannot obtain sufficient additional capital when needed, we will not be able to continue with our business strategy. In addition, significant infusions of additional capital may result in dilution to your ownership and voting rights in our securities.
Our business strategy includes acquiring interests in mature oil fields with established reserves that may possess significant remaining upside exploitation potential by implementing various secondary and tertiary enhanced oil recovery operations. We are focused on acquiring undervalued properties that feature enhanced recovery opportunities. As we continue to find acquisition candidates, we may require additional capital to finance the acquisitions as well as to conduct our EOR operations. We may not be able to obtain additional financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the additional capital required to implement our business strategy, we may be required to curtail operations or develop a different strategy, which could adversely affect our financial condition and results of operations. Further, any debt financing must be repaid and redeemable preferred stock must be redeemed regardless of whether or not we generate profits or cash flows from our business activities.
Equity financing may result in dilution to existing stockholders and may involve securities that have rights, preferences, or privileges that are senior to our common stock.
The actual quantities and present value of our proved reserves may be lower than we have estimated.
This 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 exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Approximately 80% of our total proved reserves as of June 30, 2008 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
Approximately 75% of our total proved reserves as of June 30, 2008 are undeveloped and approximately 5% are developed non-producing. While we plan to develop and produce all of our proved reserves, these reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As of June 30, 2008, estimated development costs for our PUD reserves are approximately $387,000,000 through 2015.
We may not achieve the production growth we anticipate from properties we acquire.
On May 28, 2004, we acquired Davenport Field Unit, which owned a 100% working interest in certain oil, natural gas and mineral leasehold estates and personal property related such leasehold estates located in Lincoln County, Oklahoma covering approximately 2,178 acres. On September 14, 2004, we acquired the Nowata Properties comprised of more than 220 oil and natural gas producing wells on 2,601 acres of land in Nowata County, Oklahoma. On March 29, 2005, we acquired Square One, pursuant to which we own a 100% working interest in 10,300 acres of mature oil fields in central Texas. On November 29, 2005, we acquired all of the outstanding common stock of WO Energy, pursuant to which we own oil and natural gas properties on approximately 20,000 acres in Carson, Gray and Hutchinson counties located in the Texas panhandle with 480 producing wells, 40 water disposal wells and 380 idle wells. On April 28, 2006, our wholly owned subsidiary Pantwist, LLC acquired oil and natural gas properties in the Texas panhandle, which properties cover approximately 9,700 acres with 167 wells. On March 30, 2007, our wholly owned subsidiary, Cano Petro of New Mexico, Inc., acquired oil and natural gas properties in New Mexico, which properties cover approximately 20,000 acres. Our operational strategy is to implement waterflood and EOR techniques. The performance of waterflood and EOR techniques is often difficult to predict, takes an extended period of time from first investment until actual production and we may not achieve the anticipated production growth from properties we acquire.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our recent growth is due in part to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from waterflood and EOR techniques, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in onshore United States. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.
Exploration and development drilling and the application of waterflooding and EOR techniques may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations or our application of waterflooding or EOR techniques. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The engineering data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs or our application of waterflooding or EOR techniques is not successful. Further, our drilling and other operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
•unexpected drilling conditions;
•title problems;
•pressure or irregularities in formations;
•equipment failures or accidents;
•adverse weather conditions; and
•increases in the costs of, or shortages or delays in the availability of, chemicals, drilling rigs and equipment.
The departure of key personnel could adversely affect our ability to run our business.
Our future success is dependent on the personal efforts, performance and abilities of key management, including S. Jeffrey Johnson, our Chairman and Chief Executive Officer; Benjamin Daitch, Senior Vice President and Chief Financial Officer; Patrick McKinney, Senior Vice President-Engineering and Operations; Michael J. Ricketts, Vice President and Principal Accounting Officer; and Phillip Feiner, Vice President, Corporate Secretary and General Counsel. All of these individuals are integral parts of our daily operations. We have employment agreements with all of them. We do not maintain any key life insurance policies for any of our executive officers or other personnel. To our knowledge, none of our senior management other than Morris B. Smith currently has any plans to retire or leave our company in the near future. The loss of any officer could significantly impact our business until adequate replacements can be identified and put in place.
We face strong competition from larger oil and natural gas companies, which makes it difficult to conduct profitable operations.
Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of these competitors are large, well-established companies and have substantially larger operating staffs and greater capital resources than we do. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
We are subject to many restrictions under our credit agreements which may adversely impact our future operations.
We may depend on our credit agreements for future capital needs. As required by our credit agreements with our bank lenders, we have pledged substantially all of our oil and natural gas properties as collateral to secure the payment of our indebtedness. The credit agreements restrict our ability to obtain additional financing, make investments, sell assets, grant liens, repurchase, redeem or retire our securities, enter into specific transactions with our subsidiaries or affiliates and engage in business combinations. The credit agreements prohibit us from declaring or paying dividends on our common stock. We are also required to comply with certain financial covenants and ratios.
These financial covenants and ratios could limit our ability to obtain future financing, make needed capital expenditures, withstand a downturn in our business or economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the credit agreements impose on us. Although we are currently in compliance with these covenants, in the past we have had to request waivers from or enter into amendments with our lenders to avoid default because of our anticipated non-compliance with certain financial covenants and ratios. Any future default, if not cured or waived, could result in the acceleration of all indebtedness outstanding under the credit agreements. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it, which could force us to sell significant assets or to have our assets foreclosed upon which could have a material adverse effect on our business or financial results. Even if new financing were available, it may not be on terms that are acceptable to us.
In addition, the senior credit agreement limits the amounts we can borrow to a borrowing base amount, determined by the lenders, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can independently adjust the borrowing base and the borrowings permitted to be outstanding under the senior credit agreement.
Derivative activities create a risk of potentially limiting the ability to realize profits when prices increase.
Pursuant to the terms of our senior and subordinated credit agreements, we are required to enter into commodity derivative contracts to mitigate crude oil and natural gas price risk on at least 50% and no greater than 85% of our crude oil and natural gas production attributable to PDP reserves for at least three years as of the end of each six month period ending thereafter. We have implemented commodity derivative contracts such as costless collars, purchases of price floors and sale of price ceilings. Certain commodity derivative contracts could prevent us from receiving 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 in 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. The price fluctuations in crude oil and natural gas prices, should they continue, may cause significant fluctuations to our 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.
The year ended June 30, 2007 was the first year that we were subject to Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent auditors addressing our internal controls and management's assessment. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, we may be in violation of our lending covenants, investors could lose confidence in our reported financial information, and the price of our stock could decrease as a result.
During our evaluation of disclosure controls and procedures for the year ended June 30, 2008, we concluded that we maintained effective internal control over financial reporting as of June 30, 2008, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
There can be no guarantee that we will not have deficiencies in our disclosure controls and internal controls in the future.
Our business involves many operating risks, which may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.
Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:
•fires;
•natural disasters;
•explosions;
•pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion;
•weather;
•failure of oilfield drilling and service tools;
•changes in underground pressure in a formation that causes the surface to collapse or crater;
•pipeline ruptures or cement failures;
•environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and
•availability of needed equipment at acceptable prices, including steel tubular products.
Any of these risks can cause substantial losses resulting from:
•injury or loss of life;
•damage to and destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations; and
•repair and remediation costs.
Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance policies currently provide for $1,000,000 general liability coverage for bodily injury and property damage including pollution, underground resources, blow-out and cratering. In addition, we have $1,000,000 coverage for our contractual obligations to our service contractors using their equipment downhole 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 $3,000,000 policy for control of well, redrill, and pollution on drilling wells and a $1,000,000 policy for control of well, redrill and pollution on producing wells. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
We do not insure against the loss of oil or natural gas reserves as a result of operating hazards, insure against business interruption or insure our field production equipment against loss. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.
There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations and incurrence of additional debt.
Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.
We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.
Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expense, all of which could have a material adverse effect on our financial condition and operating results.
Terrorist activities may adversely affect our business.
Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural
gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Part of our business is seasonal in nature which may affect the price of our oil and natural gas 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. As a result, our results of operations may be adversely affected by seasonal conditions. Severe weather can cause interruptions to our production and temporarily shut-in production from our wells.
We are subject to potential early repayments as well as restrictions pursuant to the terms of our Series D Convertible Preferred Stock which may adversely impact our operations.
Pursuant to the terms of our Series D Convertible Preferred Stock ("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 minimum price of at least 125% of the $1,000 per share stated value plus certain dividends. "Triggering events" include the following:
•our common stock is suspended from trading or fails to be listed on the AMEX, the New York Stock Exchange, the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market; we fail to convert and do not cure this failure within 10 business days after the conversion date or give notice of our intention not to comply with a request for conversion;
•we fail to pay for at least 5 business days any amount when and as due pursuant to the terms of the Preferred Stock or any documents related to the sale and registration rights of the Preferred Stock, common stock and warrants;
•certain actions are taken by us or third parties with regard to bankruptcy;
•we default on any indebtedness which default is not waived and the applicable grace period has expired; or
•we breach any representation, warranty, covenant or other term or condition of any document relating to the sale and registration rights regarding the Preferred Stock, the common stock and the warrants, which, to the extent such breach is curable, such breach is not cured within 7 business days.
There is no guarantee that we would be able to repay the amounts due upon an occurrence of a "triggering event."
In addition, we cannot issue any preferred stock that is senior or on par with the Preferred Stock with regard to dividends or liquidation without the approval of holders of a majority of the Preferred Stock.
We are subject to several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas which may have an adverse impact on us.
Cano and certain of its subsidiaries are defendants in several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas. The alleged damages include damage to land and livestock, remedial expenses and claims relating to wrongful death. Currently, known aggregate actual damage claims are approximately $22,600,000. However, certain plaintiffs have not provided
actual damage claims for any or all of their claims. These actual damage claims do not include the additional claims by the plaintiffs for attorneys' fees and exemplary damages, the potential amounts of which cannot be reasonably estimated. In February 2007, we entered into a Settlement Agreement with our insurance carrier pursuant to which we received $6,699,827 in exchange for releasing the insurance carrier from any future claims. $6,000,000 of the amount received related to the insurance policy limits and the remaining $699,827 related to the reimbursement of defense costs previously incurred by Cano. The $6,000,000 payment for policy limits, in accordance with the senior credit agreement, was placed in a controlled bank account and the use of the proceeds was specified to pay attorneys' fees, settlement amounts, other litigation expenses incurred to defend and/or settle the fire litigation, and for general corporate purposes. We have fully expended the $6,000,000 payment from fire litigation insurance proceeds, and there is no remaining insurance coverage for the fire litigation. We may not be able to settle any or all of the fire litigation cases on acceptable terms and may not prevail in court on any or all of such cases. If there is an adverse judgment entered against us in one or more of the fire litigation cases, based on the illiquid nature of a significant portion of our assets, we may not be able to (i) post a sufficient supersedeas bond during the appeal process of any adverse judgment, which may permit the prevailing plaintiffs to attempt to execute on any judgment pending appeal, and/or (ii) satisfy the amount of any adverse judgment.
Risks Related to Our Common Stock
Our historic stock price has been volatile and the future market price for our common stock may continue to be volatile. Further, the limited market for our shares will make our price more volatile. This may make it difficult for you to sell our common stock for a positive return on your investment.
The public market for our common stock has historically been very volatile. Since we acquired Davenport Field Unit on May 28, 2004 and through the fiscal year ended June 30, 2008, the market price for our common stock has ranged from $0.45 to $10.65. On September 10, 2008, our closing price on AMEX was $2.70. Any future market price for our shares may continue to be very volatile. This price volatility may make it more difficult for you to sell shares when you want at prices you find attractive. We do not know of any one particular factor that has caused volatility in our stock price. However, the stock market in general has experienced extreme price and volume fluctuations that often are unrelated or disproportionate to the operating performance of companies. Broad market factors and the investing public's negative perception of our business may reduce our stock price, regardless of our operating performance. Market fluctuations and volatility, as well as general economic, market and political conditions, could reduce our market price. As a result, this may make it difficult or impossible for you to sell our common stock for a positive return on your investment.
If we fail to meet continued listing standards of AMEX, our common stock may be delisted which would have a material adverse effect on the price of our common stock.
Our common stock was listed on AMEX on May 5, 2005 under the symbol "CFW." In order for our securities to be eligible for continued listing on AMEX, we must remain in compliance with certain listing standards. Among other things, these standards require that we remain current in our filings with the SEC and comply with certain provisions of the Sarbanes-Oxley Act of 2002. If we were to become noncompliant with AMEX's continued listing requirements, our common stock may be delisted which would have a material adverse affect on the price of our common stock.
If we are delisted from AMEX, our common stock may become subject to the "penny stock" rules of the Securities and Exchange Commission, which would make transactions in our common stock cumbersome and may reduce the value of an investment in our stock.
The Securities and Exchange Commission has adopted Rule 3a51-1 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that is not listed on a
national securities exchange or registered national securities association's automated quotation system and has a market price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, Rule 15g-9 requires:
•that a broker or dealer approve a person's account for transactions in penny stocks; and
•the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.
In order to approve a person's account for transactions in penny stocks, the broker or dealer must:
•obtain financial information and investment experience and objectives of the person; and
•make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.
The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the Securities and Exchange Commission relating to the penny stock market, which, in highlight form:
•sets forth the basis on which the broker or dealer made the suitability determination; and
•that the broker or dealer received a signed, written agreement from the investor prior to the transaction.
Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.
If securities analysts downgrade our stock or cease coverage of us, the price of our stock could decline.
The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, there are many large, well-established, publicly traded companies active in our industry and market, which may mean that it is less likely that we will receive widespread analyst coverage. If one or more of the analysts who do cover us downgrade our stock, our stock price would likely decline rapidly. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.
We do not pay dividends on our common stock.
We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business, including capital expenditures and to retire debt. Any decisions to pay dividends on the common stock in the future will depend upon our profitability at the time, the available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our credit agreements and our Series D Convertible Preferred Stock.
Provisions in our corporate governance and loan documents, the terms of our Series D Convertible Preferred Stock and Delaware law may delay or prevent an acquisition of Cano, which could decrease the value of our common stock.
Our certificate of incorporation, our Series D Convertible Preferred Stock, our bylaws, our loan documents and the Delaware General Corporation Law contain provisions that may discourage other persons from initiating a tender offer or takeover attempt that a stockholder might consider to be in the best interest of all stockholders, including takeover attempts that might result in a premium to be paid over the market price of our stock.
The terms of our Series D Convertible Preferred Stock permit the holders of such Preferred Stock the right to have their Series D Convertible Preferred Stock redeemed upon a "change of control." In addition, the terms of our Series D Convertible Preferred Stock do not permit us to enter into certain transactions that would constitute a "change of control" unless the successor entity assumes all of our obligations relating to the Series D Convertible Preferred Stock and the holders of a majority of our Series D Convertible Preferred Stock approve such assumption and the successor entity is publicly traded on the AMEX, the New York Stock Exchange, the Nasdaq Global Select Market, the Nasdaq Global Market or the Nasdaq Capital Market.
In addition, subject to the terms of the Series D Convertible Preferred Stock, we are authorized to issue additional shares of preferred stock. Subject to the terms of the Series D Convertible Preferred Stock and our certificate of incorporation, our board of directors has total discretion in the issuance and the determination of the rights and privileges of any shares of preferred stock which might be issued in the future, which rights and privileges may be detrimental to the holders of the common stock. It is not possible to state the actual effect of the authorization and issuance of a new series of preferred stock upon the rights of holders of the common stock and other series of preferred stock unless and until the board of directors determines the attributes of any new series of preferred stock and the specific rights of its holders. These effects might include:
•restrictions on dividends on common stock and other series of preferred stock if dividends on any new series of preferred stock have not been paid;
•dilution of the voting power of common stock and other series of preferred stock to the extent that a new series of preferred stock has voting rights, or to the extent that any new series of preferred stock is convertible into common stock;
•dilution of the equity interest of common stock and other series of preferred stock; and
•limitation on the right of holders of common stock and other series of preferred stock to share in Cano's assets upon liquidation until satisfaction of any liquidation preference attributable to any new series of preferred stock.
The terms of our Series D Convertible Preferred Stock and the provisions in our corporate governance documents regarding the granting of additional preferred stock may deter or render more difficult proposals to acquire control of our company, including proposals a stockholder might consider to be in his or her best interest, impede or lengthen a change in membership of our Board of Directors and make removal of our management more difficult. Furthermore, Delaware law imposes some restrictions on mergers and other business combinations between our company and owners of 15% or more of our common stock. These provisions apply even if an acquisition proposal is considered beneficial by some stockholders and therefore could depress the value of our common stock.
The conversion price of our Series D Convertible Preferred Stock may be lowered if we issue shares of our common stock at a price less than the existing conversion price which could cause further dilution to our common stockholders.
Subject to certain exclusions, if we issue common stock at a price less than the existing conversion price for our Series D Convertible Preferred Stock, the conversion price shall be adjusted downward which would further dilute our common stock holders upon conversion.
Our Series D Convertible Preferred Stock has voting rights both together with and separate from our common stock which could adversely affect our common stockholders.
The holders of our Series D Convertible Preferred Stock vote together with the holders of our common stock on an as converted basis, subject to a limitation on how many votes the Series D Convertible Preferred Stock holders may cast if the conversion price falls below $4.79. In addition,
approval of holders of a majority of the Series D Convertible Preferred Stock is required for us to take the following actions:
•to modify the certificate of incorporation or bylaws in a manner adverse to the Series D Convertible Preferred Stock;
•increase or decrease the number of authorized shares of Series D Convertible Preferred Stock;
•create any class of preferred stock that has a preference over or is in parity with the Series D Convertible Preferred Stock with respect to dividends or liquidation;
•purchase, repurchase or redeem any share of common stock;
•pay dividends or make any other distribution on the common stock; or
•circumvent a right of the Series D Convertible Preferred Stock.
These voting rights may have an adverse impact on the common stock and the voting power of our common stockholders.
Since we are a United States real property holding corporation, non-U.S. investors may be subject to U.S. federal income tax (including withholding tax) on gains realized on disposition of our shares, and U.S. investors selling our shares may be required to certify as to their status in order to avoid withholding.
Since we are a United States real property holding corporation, a non-U.S. holder of our common stock will generally be subject to U.S. federal income tax on gains realized on a sale or other disposition of our common stock. Certain non-U.S. holders of our common stock may be eligible for an exception to the foregoing general rule if our common stock is regularly traded on an established securities market during the calendar year in which the sale or disposition occurs. However, we cannot offer any assurance that our common stock will be so traded in the future.
If our common stock is not considered to be regularly traded on an established securities market during the calendar year in which a sale or disposition occurs, the buyer or other transferee of our common stock will generally be required to withhold tax at the rate of 10% on the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable Treasury regulations.
Item 1B.
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 has been appealed.
Other Cases
On April 28, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. ("Adcock"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence, res ipsa loquitor, trespass and nuisance and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $5,439,958. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) 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.
On July 6, 2006, Anna McMordie Henry and Joni McMordie Middleton intervened in the Adcock case. The intervenors (i) allege negligence and (ii) seek damages totaling $64,357 as well as exemplary damages.
On July 20, 2006, Abraham Brothers, LP, Edward C. Abraham, Salem A. and Ruth Ann Abraham and Jason M. Abraham intervened in the Adcock case. The intervenors (i) allege negligence, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $3,252,862. In addition, the intervenors seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors 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.
On August 9, 2006, Riley Middleton intervened in the Adcock case. The intervenor (i) alleges negligence and (ii) seeks damages totaling $233,386 as well as exemplary damages.
On April 10, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and WO Energy, Inc. ("Hutchinson"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and trespass and (ii) seek damages of $621,058, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs seek exemplary damages.
On May 1, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1923, Chisum Family Partnership, Ltd. v. Cano, W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and WO Energy, Inc. ("Chisum"). The plaintiff claims that the
electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleges negligence and trespass and (ii) seeks damages of $53,738.82, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs seek exemplary damages.
On August 9, 2006, the following lawsuit was filed in the 233rd Judicial District Court of Gray County, Texas: Cause No. 34,423, Yolanda Villarreal, Individually and on behalf of the Estate of Gerardo Villareal v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd., and WO Energy, Inc. ("Villarreal"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and (ii) seek damages for past and future financial support in the amount of $586,334, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages, for the wrongful death of Gerardo Villarreal who they claim died as a result of the fire. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable under vicarious liability theories. On August 22, 2006, relatives of Roberto Chavira intervened in the case alleging similar claims and seeking damages for lost economic support and lost household services in the amount of $894,078, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages regarding the death of Roberto Chavira.
On March 14, 2007, the following lawsuit was filed in 100th Judicial District Court in Carson County, Texas: Cause No. 9994, Southwestern Public Service Company d/b/a Xcel Energy v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and WO Energy, Inc. ("SPS"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleges negligence and breach of contract and (ii) seeks $1,876,000 in damages for loss and damage to transmission and distribution equipment, utility poles, lines and other equipment. In addition, the plaintiff seeks reimbursement of its attorney's fees.
On May 2, 2007, the following lawsuit was filed in the 84th Judicial District Court of Hutchinson County, Texas: Cause No. 37,619, Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Burgess"). Eleven plaintiffs claim that electrical wiring and equipment relating to oil and gas operations of the Company or certain of its subsidiaries started a wildfire that began on March 12, 2006 in Carson County, Texas. Five of the plaintiffs are former plaintiffs in the Adcock matter. The plaintiffs (i) allege negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $1,997,217.86. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On May 15, 2007, William L. Arrington, William M. Arrington and Mark and Le'Ann Mitchell intervened in the SPS case. The intervenors (i) allege negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $118,320. In addition, the intervenors seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors 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.
On September 25, 2007, the Texas Judicial Panel on Multidistrict Litigation granted Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and WO Energy, Inc.'s Motion to Transfer Related Cases to Pretrial Court pursuant to Texas Rule of Judicial Administration 13. The panel transferred all pending cases (Adcock, Chisum, Hutchison, Villarreal, SPS, and Burgess, identified above and Valenzuela, Abraham Equine, Pfeffer and Ayers, identified
below) that assert claims against the Company and its subsidiaries related to wildfires beginning on March 12, 2006 to a single pretrial court for consideration of pretrial matters. The panel transferred all then-pending cases to the Honorable Paul Davis, retired judge of the 200th District Court of Travis County, Texas, as Cause No. D-1-GN-07-003353.
On October 3, 2007, Firstbank Southwest, as Trustee for the John and Eddalee Haggard Trust (the "Trust") filed a Petition in intervention as part of the Hutchison case. The Trust claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The Trust (i) alleges negligence and trespass and (ii) seeks damages of $46,362.50, including, but not limited to, damages to land and certain remedial expenses. In addition, the Trust seeks exemplary damages.
On December 18, 2007, the following lawsuit was filed in the 348th Judicial District Court of Tarrant County, Texas: Cause No. 348-227907-07, Norma Valenzuela, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Valenzuela"). Six plaintiffs, including the two plaintiffs and intervenor from the nonsuited Martinez case, claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and (ii) seek actual damages in the minimum amount of $4,413,707 for the wrongful death of four relatives, Manuel Dominguez, Roberto Chavira, Gerardo Villarreal and Medardo Garcia, who they claim died as a result of the fire. In addition, plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On January 10, 2008, Philip L. Fletcher intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $120,408, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On January 15, 2008, the Jones and McMordie Ranch Partnership intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $86,250.71, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On February 11, 2008, the following lawsuit was filed in the 48th Judicial District Court of Tarrant County, Texas: Cause No. 048-228763-08, Abraham Equine, Inc. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Abraham Equine"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $1,608,000, including, but not limited to, damages to its land, livestock and lost profits. In addition, the plaintiff seeks (i) reimbursement for its attorney's fees and (ii) exemplary damages. The plaintiff also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the
200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On March 10, 2008, the following lawsuit was filed in the 352nd Judicial District Court of Tarrant County, Texas: Cause No. 352-229256-08, Gary Pfeffer v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Pfeffer"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleges negligence, trespass and nuisance, (ii) seeks undisclosed damages for the wrongful death of his father, Bill W. Pfeffer, who he claims died as a result of the fire and (iii) seeks actual damages of $1,023,572.37 for damages to his parents' home and property. In addition, the plaintiff seeks exemplary damages. The plaintiff also claims that Cano and its subsidiaries are jointly and severally liable as a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On March 11, 2008, the following lawsuit was filed in the 141st Judicial District Court of Tarrant County, Texas: Cause No. 141-229281-08, Pamela Ayers, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Ayers"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) allege negligence and (ii) seek undisclosed damages for the wrongful death of their mother, Kathy Ryan, who they claim died as a result of the fire. In addition, the plaintiffs seek exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On March 12, 2008, the following lawsuit was filed in the 17th Judicial District Court of Tarrant County, Texas, Cause No. 017-229316-08, The Travelers Lloyds Insurance Company and Travelers Lloyds of Texas Insurance Company v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Travelers"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) allege negligence, res ipsa loquitor, and trespass and (ii) claim they are subrogated to the rights of their insureds for damages to their buildings and building contents totaling $447,764.60. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership.
On August 15, 2008 the trial court denied motions for summary judgment filed by Cano in the Adcock, Chisum, Hutchison, Villarreal, SPS, Burgess, and Valenzuela cases. The SPS case is set for jury trial on February 16, 2009. None of the other above-mentioned cases are currently set for trial; however, the Company anticipates that the trial court will set these matters for jury trials.
Due to the inherent risk of litigation, the ultimate outcome of these cases and any jury trial is uncertain and unpredictable (see "Item 1A - Risk Factors-Risks Related to Our Business-We are subject to several lawsuits relating to a fire that occurred on March 12, 2006 in Carson County, Texas which may have an adverse impact on us"). However, at this time Cano management believes the suits are without merit and is vigorously defending itself and its subsidiaries.
Insurance Settlement Related to the Fire Litigation
On June 20, 2006, the following lawsuit was filed in the United States District Court for the Northern District of Texas, Fort Worth Division: C.A. No. 4-06cv-434-A, Mid-Continent Casualty Company, Plaintiff, vs. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and W.O. Energy, Inc, seeking a declaration that the plaintiff is not responsible for pre-tender defense costs and that the plaintiff has the sole and exclusive right to select defense counsel and to defend, investigate, negotiate and settle the litigation described above On September 18, 2006, the First Amended Complaint for Declaratory Judgment was filed with regard to the cases described above. Cano and its subsidiaries were served with the lawsuit between September 26-28, 2006.
On February 9, 2007, Cano and its subsidiaries entered into a Settlement Agreement and Release with the plaintiff pursuant to which in exchange for mutual releases, in addition to the approximately $923,000 that we have been reimbursed by plaintiff, the plaintiff agreed to pay to Cano within 20 business days of February 9, 2007 the amount of $6,699,827 comprised of the following: (a) the $1,000,000 policy limits of the primary policy; (b) the $5,000,000 policy limits of the excess policy; (c) $500,000 for future defense costs; (d) $144,000 as partial payment for certain unpaid invoices for litigation related expenses; (e) all approved reasonable and necessary litigation related expenses through December 21, 2006 that are not part of the above-referenced $144,000; and (f) certain specified attorneys' fees. During February 2007, we received the $6,699,827 payment from Mid-Con. Of this $6,699,827 amount, the payments for policy limits amounting to $6,000,000, in accordance with the senior credit agreement (Note 4 to the consolidated financial statements), were placed in a controlled bank account and the use of the proceeds was specified to pay attorneys' fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation, and for general corporate purposes. Specifically, we could not use the proceeds to fund capital expenditures. Accordingly, our consolidated balance sheets reflect the $6,000,000 as a liability under deferred litigation credit. As of June 30, 2008, we had fully expended the restricted cash and we no longer had a balance for restricted cash.
Other
Occasionally, we are involved in other various lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management does not believe that the ultimate resolution of any current matters that are not set forth above, 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 our business or has a material interest adverse to our business.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the quarter ended June 30, 2008.
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 American Stock Exchange ("AMEX") under the trading symbol "CFW." For the years ended June 30, 2007 and 2008, the following table sets forth the high and low sales prices per share of common stock for each quarterly period. On September 10, 2008, the closing sale price on the AMEX was $2.70.
Holders
As of September 10, 2008, our shares of common stock were held by approximately 127 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 10, 2008, there were approximately 4,000 beneficial holders who own our common stock in street name.
Dividends
We have not declared any dividends to date on our common stock. We have no present intention of paying any cash dividends on our common stock in the foreseeable future, as we intend to use earnings, if any, to generate growth. Our credit agreements do not permit us to pay dividends on our common stock. In addition, the terms of our Series D Convertible Preferred Stock do not permit us to pay dividends on our common stock without the approval of the holders of a majority of the Series D Convertible Preferred Stock.
For the year ended June 30, 2008, the preferred dividend was $4.1 million, of which $2.1 million pertained to holders of the PIK dividend option.
Except as set forth below, during the year ended June 30, 2008, there were no equity securities issued pursuant to transactions exempt from the registration requirements under the Securities Act of 1933, as amended, that were not disclosed previously in Current Reports on Form 8-K or Quarterly Reports on Form 10-Q.
On June 20, 2008, 67 shares of our Preferred Stock were converted by Investor Company, as nominee for Trapeze Capital Corp., into 11,859 shares of Cano common stock. Of the shares of common stock issued, 11,652 shares were issued based on the $5.75 conversion price of the Preferred Stock and 207 shares were issued in lieu of the accrued but unpaid dividends from April 1, 2008 to June 20, 2008 pursuant to the terms of the Preferred Stock. The shares of common stock were issued in reliance upon the exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933, as amended.
The following shares of our common stock were delivered to us during the fourth quarter of 2008 to satisfy tax withholding obligations:
These shares were delivered by Morris B. Smith pursuant to the terms of the Cano Petroleum, Inc. 2005 Long-Term Incentive Plan, to satisfy tax withholding obligations related to the vesting of his restricted stock awards.
Performance Graph
The following performance graph compares the cumulative total stockholder return on our common stock with the Standard & Poor's 500 Stock Index (the "S&P 500") and the S&P Supercomposite Oil & Gas Exploration & Production Index for the period from June 4, 2004 to June 30, 2008, assuming an initial investment of $100 and the reinvestment of all dividends, if any.
Item 6.
Item 6. Selected Financial Data
The following selected financial information (which is not covered by the report of an independent registered public accounting firm) is summarized from our results of operations for the five-year period ended June 30, 2008 and should be read in conjunction with the consolidated financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data."
(1)On July 1, 2008, we completed the sale of 7,000,000 shares of our common stock through an underwritten offering at a share price of $8.00 per share ($7.75 net to us) resulting in net proceeds of approximately $54.0 million after underwriting discounts and commissions and expenses. We used the net proceeds from the offering to pay down debt.
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 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 a forward-looking statement.
Overview
Introduction
We are a growing independent oil and natural gas company that is primarily utilizing waterflooding and enhanced oil recovery techniques to increase production and reserves at our existing properties and properties we may acquire in the future. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma. Our focus on domestic, mature oil fields eliminates exploration risk and the uncertainty of international development.
During our first three years of operations, our primary focus was to achieve growth through acquiring existing, mature oil and natural gas fields. We believe the portfolio of oil and natural gas properties that we have acquired provides ample opportunities to apply our operational strategy. We will continue to evaluate acquisition targets that are consistent with our operational strategy.
During the fiscal year ended June 30, 2008, our primary emphasis was to achieve growth by developing our existing oil and natural gas properties through development activities such as waterflooding and EOR technology. These development activities are more clearly described under "Capital Development Update."
As of June 30, 2008, we had proved reserves of 53.2 MMBOE, of which 10.6 MMBOE were PDP, 2.5 MMBOE were PDNP, and 40.1 MMBOE were PUD. PDP reserves increased by 2.1 million to 10.6 MMBOE from 8.5 MMBOE at June 30, 2007 after considering production of 0.5 MMBOE for the twelve months ended June 30, 2008. The increase in PDP reserves was primarily driven by conversion of 1.4 MMBOE from PUD to PDP based upon initial response at the Cockrell Ranch waterflood. The remaining 0.7 MMBOE increase resulted from our infill drilling program at the Cato Properties. Crude oil reserves accounted for 72% of our total reserves at June 30, 2008.
Notwithstanding our PDP growth, overall estimated proved oil and natural gas reserves decreased approximately 20% to 53.2 MMBOE as of June 30, 2008, as compared to 66.7 MMBOE as of June 30, 2007. The decrease in total proved reserves was primarily driven by revisions to our five-year development plan based on current industry practice that placed many reserves outside the window of
allowed proved reserves classification and reduced the allowed PUD locations booked per PDP location. We also adjusted our five-year development plan due to lower than expected performance at our Barnett Shale project.
Capital Development Update
For the year ended June 30, 2008 ("2008 Fiscal Year"), we incurred $89.2 million of capital expenditures ($87.8 million spent) to implement developmental projects at our existing fields to increase reserves; convert existing PUD reserves to PDP reserves, and increase production.
For the year ending June 30, 2009 ("2009 Fiscal Year"), we have a capital development budget of $97.5 million, which is projected to be spent as follows:
•$40.0 million at the Cato Properties
•$37.0 million at the Panhandle Properties
•$10.0 million at the Nowata Properties
•$ 6.7 million at the Desdemona Properties-Waterflood
•$ 3.0 million at the Desdemona Properties-Barnett Shale
•$ 0.8 million at other projects
Our capital development program includes the drilling of 114 new wells. The financing of our capital expenditures is discussed below under "Liquidity and Capital Resources." The status of our capital development activity during the 2008 Fiscal Year and planned activity during the 2009 Fiscal Year is summarized as follows:
Panhandle Properties. Proved reserves as of June 30, 2008 attributable to the Panhandle Properties are 30.1 MMBOE, of which 5.0 MMBOE are PDP and 25.1 MMBOE are PUD. As previously discussed, during the 2008 Fiscal Year, 1.4 MMBOE of PUD waterflood reserves were converted to PDP reserves based on the positive response seen at the Cockrell Ranch Unit waterflood. The 1.4 MMBOE represents approximately one-third of the June 30, 2007 PUD reserves. The remaining two-thirds continue to be classified as PUD reserves. Gross oil production during June 2008 exceeded 2,500 BOE, a three-fold increase from February 2008. Full injection of over 50,000 BWIPD is continuing at the Cockrell Ranch Unit and the cumulative injected pore volume is over 20%, or .20 PVI. Extensive well surveillance is being performed to install larger pumping units and optimize production. Additionally, 16 injection wells have been worked over to optimize and redirect water injection into the highest remaining oil saturation intervals of the Brown Dolomite formation. Total fluid production has increased to over 9,000 barrels per day and we are starting to see the first signs of increases in injection well pressure. This is the initial sign of placing injected water into "unswept" areas of the formation, which have higher remaining oil saturations, which should result in varying degrees of increasing oil production in the next three to six months.
The next project phase of our waterflood project at the Panhandle Properties consists of six separate "mini" phases on reduced well spacing that will allow us to accelerate the development of this property. The tighter spacing and smaller development patterns should allow quicker permitting and response times, and allow a larger development bandwidth over a greater acreage position in the field. We anticipate drilling 43 new wells to facilitate waterflood development. Including the increases in the Cockrell Ranch Unit, as previously discussed, field production decreased by 80 BOEPD during April and May 2008 as unscheduled gas plant maintenance and the initiation of a field-wide chemical treatment program took a large number of non-waterflood wells offline. Current Net Production is approximately 600 BOEPD.
Cato Properties. Proved reserves as of June 30, 2008 attributable to the Cato Properties are 13.5 MMBOE, of which 0.7 MMBOE are PDP, 0.7 MMBOE are PDNP and 12.1 MMBOE are PUD. These properties include roughly 20,000 acres across three fields in Chavez and Roosevelt Counties, New Mexico. The prime asset is the roughly 15,000 acre Cato Field, which produces from the historically prolific San Andres formation, which has been successfully waterflooded in the Permian Basin for over 30 years. There were two successful waterflood pilots conducted in the field in the 1970's by Shell and Amoco. We believe the PDP reserve increase of 0.7 MMBOE resulting from our infill drilling program during the 2008 Fiscal Year provides support for our plans for continued capital development at the Cato Properties. The drilling results for the 2008 Fiscal Year included 30 wells drilled, 28 of which were to develop the Cato waterflood on 20-acre spacing. Two wells were drilled on 40 acre spacing to test other undrilled acres of the field. Additionally, over 35 wells were returned to production ("RTP"). The results of our RTP program and drilling increased production from 35 BOEPD during April 2007 to over 240 BOEPD in April 2008. The development plan for the 2009 Fiscal Year is to drill 48 new waterflood pattern wells and initiate water injection. We presented our waterflood application to the New Mexico Oil and Gas Conservation Commission in May 2008 and stand ready to commence ten water injection wells once the permit application is approved. We will be in a position to initiate water injection in ten additional wells at the Cato field within 60 days of permit receipt. Current Net Production is approximately 350 BOEPD. During May 2008, we released the drilling rig to concentrate on waterflood facility infrastructure and no new wells have been brought on-line since then. In July 2008, we reinstated our drilling program. Pipe was set on the first new well on July 10, 2008. Production is expected to increase from the restarted 20-acre infill drilling program in the near-term.
Desdemona Properties. Proved reserves as of June 30, 2008 attributable to the Desdemona Properties are 4.0 MMBOE, of which 0.5 MMBOE are PDP, 1.2 MMBOE are PDNP and 2.3 BOE are PUD. Current Net Production is approximately 65 BOEPD.
Desdemona Properties-Waterflood. We drilled and completed 11 required replacement wells to initiate the development of the Duke Sand Waterflood on the Desdemona Properties during the 2008 Fiscal Year. Procurement and infrastructure development of the waterflood facilities was completed in September 2007. Water injection commenced in September 2007. To date, we have injected over 1 million barrels of water into a pilot location of the Duke Sand reservoir. Since this is a peripheral flood pattern, the time between pumping water into the reservoir and a response will be longer than at conventional patterns. We continue to monitor the results and while we have seen positive oil production and fluid production levels in the pattern wells, we do not expect to see meaningful response from this waterflood until the second calendar quarter of 2009. Contingent on the success of the pilot, we have planned capital expenditures of $6.7 million for the continued development of this waterflood.
Desdemona Properties-Barnett Shale. We have successfully drilled and completed wells in the Barnett Shale formation in Eastland, Erath and Commanche Counties, located approximately 50 miles west of established Barnett Shale production in the Fort Worth Basin, Texas. We drilled fifteen vertical wells during the fiscal year ended June 30, 2007 (the "2007 Fiscal Year") to delineate the lateral extent of the Barnett Shale formation within the roughly 11,000 acres of our Desdemona Properties. The results of the vertical well test program provided encouraging results that allowed us to initiate our Horizontal Well Development Program in the field.
We drilled four horizontal wells at the end of the 2007 Fiscal Year and continued with four more early in the 2008 Fiscal Year. Our 2007 Fiscal Year year-end reserves were based on our vertical test results and analogs. We internally estimated 80 total horizontal locations on roughly 120 acre spacing, of which 76 future horizontal locations were considered for PUD reserves. We booked proved reserves of 6.8 MMBOE for the Barnett Shale at June 30, 2007. Of this amount, 6.0 MMBOE were PUD reserves. We also have the Marble Falls formation re-completion potential
in all of our vertical and horizontal Barnett Shale wells. Based on the three existing Marble Falls re-completions producing in the field for the 2007 Fiscal Year, we booked 4.0 MMBOE of proved reserves, of which 3.9 MMBOE were PUD reserves in the Marble Falls formation. In response to low natural gas prices during the first quarter of our 2008 Fiscal Year, we elected to defer the drilling program in the Barnett Shale. Since there was no drilling for the remainder of the 2008 Fiscal Year, normal field decline was experienced. For determining year-end reserves for the 2008 Fiscal Year, we considered the lower performance from the existing wells and, based on current industry practice, limited the number of PUD locations that could be booked against existing wells. Therefore, PUD reserves were reduced by approximately 3 MMBOE due to lower performance results from the existing wells and further reduced by another 5 MMBOE as the number of PUD drilling locations decreased from 76 to 40. These horizontal wells had high initial rates of over 1.5 MMCFPD but experienced a large amount of water production. We subsequently received permission from the Texas Railroad Commission to inject the Barnett Shale water production into our Desdemona Duke Sand Waterflood project. Barnett Shale production for 2008 Fiscal Year averaged approximately 600 MCFPD. We have budgeted $3 million in our 2009 Fiscal Year capital development budget to drill two Barnett Shale wells to test other areas of the field and to ensure additional water supply for the Duke Sand Waterflood project
Nowata Properties. Proved reserves as of June 30, 2008 attributable to the Nowata Properties are 1.5 MMBOE, all of which are PDP. Current Net Production is approximately 220 BOEPD. Our ASP tertiary recovery pilot project has been in full operation since December 2007. To date, we have injected close to .12 PVI of ASP. We expect an initial response to the ASP pilot by the end of the 2008 calendar year. We also plan to drill ten new wells during the 2009 Fiscal Year if we receive positive results from the ASP pilot.
Davenport Properties. Proved reserves as of June 30, 2008 attributable to the Davenport Properties are 1.5 MMBOE, of which 1.0 MMBOE are PDP and 0.5 MMBOE are PDNP. Current Net Production is approximately 80 BOEPD. During the 2008 Fiscal Year, we returned five injector wells and four producing wells as we progressed toward optimizing the waterflood pattern. We are currently evaluating the sale of these properties.
Pantwist Properties. Proved reserves as of June 30, 2008 attributable to the Pantwist Properties are 2.4 MMBOE, of which 1.9 MMBOE are PDP and 0.5 MMBOE are PUD. Current Net Production is approximately 320 BOEPD. On September 5, 2008, we entered into an agreement to sell our 100% membership interest in Pantwist, LLC for $42.7 million cash, subject to closing adjustments. The sale has an effective date of July 1, 2008 and we expect to finalize the sale on or before October 1, 2008. The primary asset of the Pantwist, LLC is the Pantwist Properties.
Corsicana Properties. The Corsicana Properties were the subject of a proved surfactant-polymer chemical injection pilot in the 1980s. Proved reserves as of June 30, 2008 attributable to the Corsicana Properties is 114 MBOE, of which 16 MBOE are PDP and 98 MBOE are PUD. We drilled and completed 16 pattern replacement wells in order to reinstate a prior waterflood in this field during the 2007 Fiscal Year. We received the required permits to inject water in June 2007. The waterflood was successfully re-instated in December 2007. We achieved full injection of 4,000 BWIPD and are monitoring initial flood results. We experienced production rates of 2 to 6 BOEPD during the quarter ended June 30, 2008. We have been pleased with the remaining oil saturations in this field and coupled with the prior successful polymer pilot in this field in the 1980's, we believe this field is a prime ASP candidate. Once the waterflood response and laboratory results are analyzed, we anticipate evaluating an ASP pilot in the field during the second half of calendar year 2008. Current Net Production is approximately 3 BOEPD.
After paying down outstanding debt and the possible payment of a portion of the Series D Preferred Stock, based on the positive development results seen from our 2008 Fiscal Year capital
programs at the Panhandle and Cato Properties, we expect to commit any remaining net proceeds from the sale of the Pantwist Properties, as previously discussed, to continued development of these two properties and/or to strategic acquisitions.
Industry Conditions
We believe significant acquisition opportunities exist and will continue to exist as major energy companies and larger independents continue to focus their attention and resources toward the discovery and development of large fields. Management expects the trend of the past several years to continue where larger companies have been divesting mature oilfields. This trend should provide ample opportunities for smaller independent companies to acquire and exploit mature U.S. fields. We expect, however, that there will be increased competition for such properties in the future.
Our Strategy
•Exploit and Develop Existing Properties. We believe we have acquired an attractive portfolio of assets to implement our business plan. We intend to add proved reserves to, and increase production from, our existing properties through the application of advanced EOR technologies, including water, gas and chemical flooding and other techniques.
•Acquire Strategic Assets. We seek to acquire low-cost assets with reserves suitable for EOR techniques in the onshore U.S. We will continue to target acquisitions that meet our engineering and operational standards in a financially prudent manner.
•No Exploration Risk. Our portfolio is comprised of mature fields with proven reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on exploration drilling and the high degree of speculation associated with making new discoveries.
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 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 oil and natural gas as well as price volatility. See "Risk Factors."
Liquidity and Capital Resources
Our primary sources of capital and liquidity have been issuance of equity securities, borrowings under our credit agreements, and cash flows from operating activities. These sources are discussed in greater detail below.
Common Issuance Completed July 1, 2008
On July 1, 2008, we completed the sale of 7,000,000 shares of our common stock through an underwritten offering at a share price of $8.00 per share ($7.75 net to us) resulting in net proceeds of approximately $54.0 million after underwriting discounts and commissions and expenses.
We used the net proceeds of approximately $54.0 million from the offering to pay down debt which will subsequently be drawn in order to finance (i) existing development activities in certain core areas such as the Panhandle and Cato properties, (ii) selective acquisitions and (iii) general corporate purposes.
Private Placement
On November 7, 2007, we sold in a private placement 3.5 million shares of our common stock at $7.15 per share for net proceeds of $23.4 million after deducting issuance costs of $1.6 million. The net proceeds were used to pay down our long-term debt due under our senior credit agreement.
Warrants
As discussed below under "September 2006 Financing," we had outstanding warrants totaling 1,646,061 common shares at an exercise price of $4.79 per share that were to expire on March 6, 2008. The warrants were exercised as follows:
•1,084,345 warrants were exercised for cash for which we received $5.2 million for the issuance of 1,084,345 common shares.
•561,291 warrants were exercised in a cashless manner, for the issuance of 144,506 common shares.
•425 warrants were not exercised, and expired pursuant to their terms.
As of June 30, 2008, we no longer have any outstanding warrants.
September 2006 Financing
On September 6, 2006, we sold in a private placement 49,116 shares of Series D Convertible Preferred Stock at a price of $1,000.00 per share and 6,584,247 shares of common stock at a price of $4.83 per share, the three day average closing price of the stock prior to the execution of the definitive agreements, plus a warrant component. The Preferred Stock has a 7.875% dividend and features a paid-in-kind ("PIK") provision that allows, at the investor's option, the investor to receive additional shares of common stock upon conversion for the dividend in lieu of a cash dividend payment. Holders of approximately 55% of the Preferred Stock chose the PIK dividend option. The Preferred Stock is convertible to common stock at a price of $5.75 per share and the common stock was subject to 25% warrant coverage at an exercise price of $4.79 per share. The warrant component provided for the purchase of 1,646,061 common shares and expired on March 6, 2008, as previously discussed. 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. Gross proceeds from the transactions were $80.9 million, of which $49.1 million was attributable to the Preferred Stock, and $31.8 million was attributable to the common stock and warrants. Net proceeds were $75.5 million after deducting issuance costs of $5.4 million.
Cash proceeds from the September 2006 financing were used to repay long-term debt (Note 4 to the consolidated financial statements), for general corporate purposes and to fund our capital expenditures development.
For the twelve months ended June 30, 2008, the preferred dividend was $4.1 million, of which $2.1 million pertained to holders of the PIK dividend option. For the twelve months ended June 30, 2007, the preferred dividend was $3.2 million, of which $1.7 million pertained to holders of the PIK dividend option.
Credit Agreements
At June 30, 2008, our total outstanding long-term debt was $73.5 million, which consisted of $58.5 million due under the senior credit agreement and $15.0 million due under the subordinated credit agreement. At June 30, 2008 and 2007, the weighted average interest rate for the two agreements was 6.33% and 7.46%, respectively. As discussed under Note 2 to the consolidated financial statements, we received $54.0 million from the sale common stock completed on July 1, 2008. The pro forma
balance sheet information presented as part of our consolidated balance sheets reflects the use of the $54.0 million proceeds to paydown long-term debt, which reduced the long-term debt balance to $19.5 million at July 1, 2008. The senior and subordinated credit agreements are discussed in greater detail below.
Senior Credit Agreement
On November 29, 2005, we entered into a $100 million senior credit agreement with lenders led by Union Bank of California, N.A. ("UBOC"), as administrative agent and as issuing lender. Pursuant to the terms of the senior credit agreement, a borrowing base based on our proved reserves is redetermined every six months with one optional redetermination allowed between scheduled redeterminations. On September 7, 2007, the lenders approved the borrowing base amount of $60.0 million, which remains unchanged at June 30, 2008. As of June 30, 2008, the unused borrowing base commitment was $1.5 million. As a result of the previously discussed $54.0 million paydown on July, 1, 2008, the unused borrowing base commitment was $55.5 million as of July 1, 2008. As of September 8, 2008, the unused borrowing base commitment was $46.3 million.
The outstanding principal is due on or before November 29, 2009 unless, pursuant to the terms of the senior credit agreement, specific events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults; breaches of representations and warranties-, and covenants insolvency; a "change of control" in our ownership as described in the senior credit agreement, and a "material adverse change" as described in the senior credit agreement.
Subject to certain restrictions, the senior credit agreement permits the issuance of convertible notes and equity. If we are not in default under the senior credit agreement, we may make interest payments on any convertible notes and dividend payments on any preferred equity securities.
The senior credit agreement requires us to comply with certain credit metrics, such as certain ratios of debt to EBITDA (as defined in the senior credit agreement), current assets to current liabilities, and EBITDA to interest. Each metric is further defined below.
The leverage ratio is as follows: (a) for each fiscal quarter ending prior to December 31, 2008, the ratio of (i) Consolidated Debt (as defined in the senior credit agreement) to (ii) consolidated EBITDA for the four fiscal quarter period then ended must not be greater than 5.00 to 1.00; (b) at the end of each fiscal quarter ending on or after December 31, 2008 but prior to June 30, 2009, the ratio shall not be greater than 4.50 to 1.00; and (c) at the end of each fiscal quarter ending on or after June 30, 2009, the ratio shall not be greater than 4.00 to 1.00. For the purposes of calculating the leverage ratio, the definition of "Consolidated Debt" shall not include "Debt" outstanding under Preferred Stock as discussed in Note 2 to the consolidated financial statements. Amendment No. 12, effective as of June 30, 2008, permitted us to reduce Consolidated Debt by the $54.0 million of proceeds from the sale of common stock discussed in Note 2 to the consolidated financial statements in order to compute the leverage ratio at June 30, 2008.
The current ratio specifies that the ratio of (i) current assets to (ii) current liabilities must not be less than 1:00 to 1:00 for each financial quarter. For purposes of computing the current ratio, current assets and liabilities arising from SFAS Nos. 133 and 143 shall be excluded. The definition of current assets includes un-borrowed amounts under our borrowing base. Amendment No. 11, dated as of June 27, 2008, permits us to increase the unborrowed amount under the borrowing base by the $54.0 million of proceeds from the sale of common stock discussed in Note 2 to the consolidated financial statements in order to compute the current ratio at June 30, 2008.
The interest coverage ratio is the ratio of our consolidated EBITDA for the four fiscal quarter period then ended to our consolidated Interest Expense for the four fiscal quarters then ended and must be at least 2.00 to 1.00. The definition of "Interest Expense" shall include cash dividends paid under our Preferred Stock, but shall exclude PIK (non-cash) dividends under Preferred Stock, as discussed in Note 2 to the consolidated financial statements.
We were in compliance with these metrics as of June 30, 2008.
At our option, the interest rate is computed based on either (i) on the prime rate plus the applicable margin ranging up to 1.00% based on the utilization level or (ii) on the LIBOR rate applicable to the interest period plus the applicable margin ranging from 1.75% to 2.50% based on the utilization level. At June 30, 2008 and 2007, the interest rate was 5.76% and 7.46%, respectively. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.
The senior credit agreement imposes certain restrictions on us and our subsidiaries, subject to specific exceptions, including, but not limited to, the following: (i) incurring additional liens; (ii) incurring additional debt; (iii) merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property; (iv) making certain payments, including cash dividends to our 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 interests in any person or any oil and natural gas properties or activities related to oil and natural gas properties unless with regard to new oil and natural gas properties, such properties are mortgaged to UBOC, as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage in favor of UBOC, 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.
In addition, we are required to hedge our exposure to commodity price risk associated with expected oil and natural gas production. The senior credit agreement requires the hedges to cover no less than 50% and no greater than 85% of our crude oil and natural gas production attributable to PDP reserves for at least three years as of the end of each six month period. Our commodity derivatives are further discussed in Note 5 to the consolidated financial statements.
As security for our obligations under the senior credit agreement: (i) eight of our subsidiaries have guaranteed all of our obligations; (ii) we, together with eight of our subsidiaries, have executed mortgages in favor of UBOC, as collateral trustee, covering oil and natural gas properties located in Texas, Oklahoma and New Mexico; (iii) we, together with eight of our subsidiaries, have granted a security interest in favor of UBOC, as collateral trustee, in substantially all of our assets; and (iv) we and two of our subsidiaries have pledged our ownership interests in eight of our subsidiaries to UBOC, as collateral trustee.
Subordinated Credit Agreement
On March 17, 2008, we entered into a $25.0 million subordinated credit agreement with UnionBanCal Equities, Inc. ("UBE") as the administrative agent. The initial amount available for borrowing was $15.0 million which was drawn on March 18, 2008 and used to reduce the outstanding amount under our $100.0 million senior credit agreement. Pursuant to the terms of the subordinated credit agreement, we may request additional borrowings of up to $10.0 million with the lenders determining in their own discretion whether to permit such additional borrowings. Any additional borrowings must be used to reduce the outstanding amount under the senior credit agreement.
At our option, the interest rate is computed based on either (i) the prime rate plus the applicable margin of (a) 4.75% if the Consolidated Debt (as defined in the subordinated credit agreement) to
consolidated EBITDA (as defined in the subordinated credit agreement) ratio is less than or equal to 4.00 to 1.00 or (b) 5.00% if the Consolidated Debt to consolidated EBITDA ratio is greater than 4.00 to 1.00 or (ii) the LIBOR rate plus the applicable margin of (a) 5.75% if the Consolidated Debt to consolidated EBITDA ratio is less than or equal to 4.00 to 1.00 or (b) 6.00% if the Consolidated Debt to consolidated EBITDA ratio is greater than 4.00 to 1.00. At June 30, 2008, the interest rate was 8.56% based on LIBOR plus 5.75%. If the interest rate is based on the prime rate, interest payments are due quarterly, and if the interest rate is based on the LIBOR rate, interest payments are due every three months.
Unless specific events of default occur, the maturity date is March 17, 2011, subject to our right to request up to two extensions of one year each with the lenders determining in their own discretion whether to permit such extensions. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, breaches of representations and warranties and covenants by us, certain cross-defaults, insolvency, a change in control or a material adverse change (as both terms are defined in the subordinated credit agreement). All unpaid principal and interest amounts are due at maturity.
The subordinated credit agreement contains certain negative covenants for us including, but not limited to, covenants, subject to certain exceptions, against the following: (i) incurring additional liens, (ii) incurring additional debt; (iii) merging or consolidating or selling, 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.
We must also comply with certain financial ratios previously described under "Senior Credit Agreement". The current ratio must not be less than 1.00 to 1.00 for each fiscal quarter. Amendment No. 1 dated as of June 27, 2008 permits us to increase the current assets by the $54.0 million of proceeds from the sale of common stock previously discussed in Note 2 to the consolidated statements in order to compute the current ratio at June 30, 2008. The leverage ratio must not be greater than 5.00 to 1.00. Amendment No. 2 dated as of June 30, 2008 permits us to reduce Consolidated Debt by the $54.0 million of proceeds from the sale of common stock discussed in Note 2 to the consolidated financial statements in order to compute the leverage ratio at June 30, 2008.The interest coverage ratio must not be less than 1.50 to 1.00. The subordinated credit agreement also specifies that the ratio of Total Present Value (as defined in the subordinated credit agreement) to Consolidated Debt must not be less than 1.50 to 1.00. We were in compliance with these ratios as of June 30, 2008.
In addition, we are required to maintain the current hedges as summarized in Note 5 to the consolidated financial statements until their stated maturity and, unless otherwise agreed by the lenders, we are required to maintain hedges covering at least 50% and no greater than 85% of our crude oil and natural gas production attributable to PDP reserves for at least three years as of the end of each six month period.
As security for our obligations under the subordinated credit agreement: (i) eight of our subsidiaries have guaranteed all of our obligations; (ii) we, together with eight of our subsidiaries; have executed mortgages covering oil and natural gas properties located in Texas, Oklahoma and New Mexico; (iii) we, together with eight of our subsidiaries, have granted a security interest in substantially
all of our assets; and (iv) we and two subsidiaries have pledged our ownership interests in eight of our subsidiaries.
Cash Flows from Operating Activities and Other Capital Resources
At June 30, 2008, our cash balance was $0.7 million. We had cash provided by operating activities of $17.0 million during the 2008 Fiscal Year, which was an improvement of $14.3 million as compared to the $2.7 million provided by operations for the 2007 Fiscal Year. The $14.3 million improvement is largely attributable to improved earnings from operations as discussed under "Results of Operations-Years Ended June 30, 2008, 2007, and 2006" and to the release of restrictions related to $6.0 million of restricted cash. As discussed in Note 12 to the consolidated financial statements, an amendment to the senior credit agreement permits use of the $6.0 million of restricted cash for general corporate purposes, in addition to attorneys' fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation discussed in Note 12 to the consolidated financial statements. As of June 30, 2008, we had fully expended the restricted cash and we no longer had a balance for restricted cash. At June 30, 2008, we had unused borrowing capacity of $1.5 million; however, after the $54.0 million paydown of long-term debt from the equity issuance completed on July 1, 2008, as discussed in Note 2 to the consolidated financial statements, we had unused borrowing capacity of $55.5 million. The average interest rate of our debt was 6.33% at June 30, 2008.
We believe the combination of cash on hand, cash flow generated from operations, available debt of $55.5 million under our credit agreements (as of June 30, 2008, pro-forma for the effect of the July 2008 equity capital raise, as previously discussed), and access to the capital markets for future public and/or private debt or equity issuances should be sufficient to finance our working capital needs and the $97.5 million capital expenditure program for the 2009 Fiscal Year, discussed under "Overview-Capital Development Update." However, no assurance may be given that we will be successful in improving our operating results, the success of our field developmental activities during the next twelve months or that we can successfully access capital markets for debt or equity issuances.
On September 5, 2008, we entered into an agreement to sell our 100% membership interest in Pantwist, LLC for $42.7 million cash, subject to closing adjustments. The sale has an effective date of July 1, 2008, and we expect to finalize the sale on or before October 1, 2008. The primary asset of the Pantwist, LLC is the Pantwist Properties. After paying down outstanding debt and the possible payment of a portion of the Series D Preferred Stock, we expect to commit any remaining net proceeds from the sale of the Pantwist Properties, when finalized, to continued development of the Panhandle and Cato Properties and/or to strategic acquisitions.
Results of Operations-Years Ended June 30, 2008, 2007, and 2006
Overall
For the 2008 Fiscal Year, we had a loss applicable to common stock of $21.6 million, which is $17.6 million higher than the $4.0 million loss applicable to common stock for the 2007 Fiscal Year. Increased revenues of $16.3 million, increased deferred tax benefit of $7.9 million and lower interest expense of $1.3 million were more than offset by higher unrealized loss on commodity derivatives of $27.6 million, increased operating expenses of $8.4 million, lower income from discontinued operations of $2.7 million, reduced income from realized gain (loss) on commodity derivatives of $3.5 million and higher Preferred Stock dividends of $0.9 million representing a full year of dividends in the 2008 Fiscal Year.
For the 2007 Fiscal Year, we had a loss applicable to common stock of $4.0 million, which is $2.2 million higher than the $1.8 million loss applicable to common stock incurred for the year ended June 30, 2006 ("the 2006 Fiscal Year"). Increased revenues of $12.5 million, increased income from discontinued operations of $2.2 million, decreased unrealized loss on commodity derivatives of
$1.4 million and increased income from realized gain (loss) on commodity derivatives of $0.4 million were more than offset by increased operating expenses of $13.6 million, increased Preferred Stock dividends of $3.2 million, as the 2006 Fiscal Year did not have Preferred Stock, and decreased deferred income tax benefit of $1.9 million.
Operating Revenues
The table below summarizes our operating revenues for the years ended June 30, 2008, 2007, and 2006.
2008 Fiscal Year v. 2007 Fiscal Year
The 2008 Fiscal Year operating revenues of $44.7 million represent an improvement of $16.3 million as compared to the 2007 Fiscal Year operating revenues of $28.4 million. The $16.3 million improvement is primarily attributable to:
•Higher realized prices received for crude oil and natural gas sales, as shown in the above table, which led to increases of $9.9 million and $5.4 million, respectively, and
•Including a full twelve months of Cato Properties operating revenues versus three months in 2007 Fiscal Year.
2007 Fiscal Year v. 2006 Fiscal Year
The 2007 Fiscal Year operating revenues of $28.4 million represent an improvement of $12.5 million as compared to the 2006 Fiscal Year operating revenues of $15.9 million. The $12.5 million improvement is primarily attributable to:
•Including a full twelve months of Panhandle and Pantwist Properties operating revenues in the 2007 Fiscal Year versus the 2006 Fiscal Year including seven months of Panhandle Properties' revenue and two months of Pantwist Properties' revenue,
•Increased production from the Desdemona, Davenport and Nowata Properties ($0.4 million and 9 MBOE of sales), and
•Including three months of operating revenues for the acquired Cato Properties in the 2007 Fiscal Year.
The average price we received for our crude oil sales is generally at or above market prices received at the wellhead (other than at the Cato Properties). The average price we receive for our natural gas sales is approximately the market price received at the wellhead less transportation and marketing expenses.
We expect to grow sales through our development plans as previously discussed under
"Overview-Capital Development Update."
Operating Expenses
2008 Fiscal Year v. 2007 Fiscal Year
For the 2008 Fiscal Year, our total operating expenses were $39.0 million, or $8.4 million higher than the 2007 Fiscal Year of $30.6 million. The $8.4 million increase is primarily attributed to:
•increased lease operating expenses of $4.6 million,
•higher general and administrative expenses of $2.1 million,
•higher production and ad valorem taxes of $0.9 million, and
•increased depletion and depreciation expense of $0.7 million.
2007 Fiscal Year v. 2006 Fiscal Year
For the 2007 Fiscal Year, our total operating expenses were $30.6 million, or $13.6 million higher than the 2006 Fiscal Year operating expenses of $17.0 million. The $13.6 million increase is primarily attributed to:
•Including a full twelve months of Panhandle and Pantwist Properties operating expenses in the 2007 Fiscal Year, accounted for $6.9 million of the increase. The 2006 Fiscal Year included seven months of Panhandle Properties' operating activities and two months of Pantwist Properties' operating activities,
•Higher general and administrative expenses of $5.2 million, and
•Higher operating expenses due to increased sales volumes, as discussed under "Operating Revenues."
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 2008 Fiscal Year, our LOE was $15.5 million, which is $4.6 million higher as compared to the 2007 Fiscal Year LOE of $10.9 million. We have incurred higher LOE due to the inclusion of the Cato Properties, increased lifting costs at the Desdemona Properties, increased workover rig expenses at the Panhandle and Pantwist Properties, increased electricity expense, increased crude oil and natural gas sales (as discussed previously) and generally higher costs for goods and services. The 2008 Fiscal Year has a full year of Cato Properties' operating results versus three months in the 2007 Fiscal Year. Our LOE per BOE has increased from $21.78 during the 2007 Fiscal Year to $29.53 for the 2008 Fiscal Year, for the reasons previously discussed.
For the 2007 Fiscal Year, our LOE was $10.9 million, which is $4.6 million higher as compared to the 2006 Fiscal Year LOE of $6.2 million. The $4.6 million increase is attributable to the inclusion of a full twelve months of Panhandle and Pantwist Properties operating results, and to support increased crude oil and natural gas sales volumes, as previously discussed under "Operating Revenues." For the 2007 Fiscal Year, the LOE per BOE was $21.78, which was lower than the LOE per BOE of $22.10 incurred during the 2006 Fiscal Year.
We generally incur a high amount of LOE because our fields are more mature and typically produce less oil and more water, and they are generally at the end of the primary or secondary production cycle. However, we expect the LOE per BOE to decrease during the 2009 Fiscal Year as
production increases from the waterflood and EOR development activities we are implementing as discussed under the "Overview-Capital Development Update."
General and Administrative Expenses
Our general and administrative ("G&A") expenses consist of support services for our operating activities and investor relations costs.
2008 Fiscal Year v. 2007 Fiscal Year
For the 2008 Fiscal Year, our G&A expenses totaled $14.9 million, which is $2.1 million higher than Fiscal Year 2007 of $12.8 million. The primary contributors to the $2.1 million increase were:
•Increased stock compensation expense of $2.1 million resulting from the issuance of stock options as discussed in Note 8 to the consolidated financial statements and the issuance of restricted shares as discussed in Note 9 to the consolidated financial statements,
•Increased labor and staffing costs of $0.3 million, which includes the accrual of bonuses earned during the 2008 Fiscal Year and the payment of bonuses during the quarter ended December 31, 2007, and
•Higher legal fees of $0.3 million pertaining to the fire litigation as discussed in Note 12 to the consolidated financial statements.
These increases were partially offset by lower fees of $0.3 million for accounting services to achieve full compliance with Section 404 of the Sarbanes-Oxley Act and reductions totaling $0.3 million pertaining to other expenses.
For the 2008 Fiscal Year and 2007 Fiscal Year, our payroll and payroll-related costs were $4.4 million and $4.1 million, respectively, of our total G&A expenses. We expect these costs to continue to increase because the recent growth in the petroleum industry has increased competition for labor resources and because we seek to increase total employees due to continued growth.
2007 Fiscal Year v. 2006 Fiscal Year
For the 2007 Fiscal Year, our G&A expenses totaled $12.8 million, which is $5.2 million higher than the 2006 Fiscal Year G&A expenses of $7.6 million. The primary contributors to the $5.2 million increase were:
•Increased labor and staffing costs of $1.4 million,
•Higher legal fees of $1.6 million to comply with regulatory requirements and for litigation,
•Increased fees of $0.8 million for accounting services we incurred in connection with SEC reporting and to achieve full compliance with the Section 404 of the Sarbanes-Oxley Act,
•Added expenses of $0.4 million to maintain the Panhandle Properties' offices, and
•Other increases totaling $1.0 million including, higher office rent expenses, increased board of director compensation and increased insurance costs.
Depletion and Depreciation
For the 2008 Fiscal Year, our depletion and depreciation expense was $5.0 million, an increase of $0.7 million as compared to the 2007 Fiscal Year depletion and depreciation expense of $4.3 million. This includes depletion expense pertaining to our oil and natural gas properties, and depreciation expense pertaining to our field operations vehicles and equipment, natural gas plant, office furniture and computers. The increase is due to increased crude oil and natural gas sales volumes as previously
discussed under "Operating Revenues" and higher per BOE depletion rates. For the 2008 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $8.26 per BOE, as compared to 2007 Fiscal Year rate of $7.08 per BOE. The higher depletion rates resulted from a reduction of reserves for the Desdemona-Barnett Shale and Pantwist Properties, as discussed in Note 14 to the consolidated financial statements, and higher depletion rates attributed to the Cato Properties.
For the 2007 Fiscal Year, our depletion and depreciation expense was $4.3 million, an increase of $2.5 million as compared to the 2006 Fiscal Year depletion and depreciation expense of $1.8 million. The increase is due to increased crude oil and natural gas sales volumes as previously discussed under "Operating Revenues" and higher depletion rates. For the 2007 Fiscal Year, our depletion rate pertaining to our oil and gas properties was $7.08 per BOE as compared to the 2006 Fiscal Year rate of $5.85 per BOE. The higher depletion rates are attributable to higher rates pertaining to the gas production from the Desdemona-Barnett Shale Property, reduced proved producing reserves for the Panhandle Properties and higher rates attributed to the Cato Properties acquired in March 2007.
Production and Ad Valorem Taxes
For the 2008, 2007 and 2006 Fiscal Years, production and ad valorem taxes were $3.4 million, $2.5 million, and $1.2 million, respectively. The annual increases are attributable to higher revenues, as previously discussed.
Interest Expense
For 2008, 2007 and 2006 Fiscal Years, we incurred interest expense of $1.0 million, $2.3 million and $2.3 million, respectively, as a direct result of the credit agreements we entered into, as discussed in Note 4 to the consolidated financial statements and under "Liquidity and Capital Resources-Credit Agreements." The interest expense for the 2008 and 2007 Fiscal Years was impacted by $2.5 million and $0.3 million, respectively, of interest cost that was capitalized to the waterflood and ASP projects discussed under the "Overview-Capital Development Update." The total interest cost (including capitalized interest) of $3.5 million during the current year is $0.9 million higher than the comparable amount of $2.6 million for the prior year due to higher debt balances incurred during the current year. The total interest cost of $2.6 million for the 2007 Fiscal Year is comparable to that of the 2006 Fiscal Year.
Unrealized Loss on Commodity Derivatives
As discussed in Note 5 to the consolidated financial statements, as required by our credit agreements, we have entered into commodity derivative contracts for crude oil and natural gas production. For the 2008 Fiscal Year, we recorded an unrealized loss of $29.4 million to reflect the fair value of the commodity derivatives as of June 30, 2008. The $29.4 million unrealized loss is $27.6 million higher than the 2007 Fiscal Year unrealized loss of $1.8 million. The 2006 Fiscal Year unrealized loss was $3.2 million.
The unrealized loss is a non-cash charge resulting from the mark-to-market valuation of our commodity derivatives that pertains to future periods. Of the $29.4 million amount for the 2008 Fiscal Year, $26.5 million pertained to the costless collars, which did not require any initial cash outlay and do not involve future cash outlay unless the NYMEX crude oil and natural gas prices exceed the ceiling prices as specified in the table in Note 5 to the consolidated financial statements.
Regarding the $29.4 million unrealized loss on commodity derivatives for the 2008 Fiscal Year, $23.8 million occurred during the quarter ended June 30, 2008. This resulted from significant price increases for both oil and natural gas during the quarter ended June 30, 2008 which increased our derivative liabilities due under our commodity derivatives at June 30, 2008.
By their nature, the value of these commodity derivatives can be highly volatile which can cause fluctuations in our earnings. A ten percent change in these prices for our derivative instruments can impact earnings by approximately $2.6 million.
Realized Gain (Loss) on Commodity Derivatives
During the 2008 Fiscal Year, there were net settlements under our derivative agreements due to our counterparty of $2.6 million, as compared to the 2007 and 2006 Fiscal Years for which we received net settlements from our counterparty of $1.0 million and $0.5 million, respectively.
For the 2008, 2007 and 2006 Fiscal Years, the settlements received by us primarily resulted from cumulative monthly payments we received from a counterparty since the NYMEX natural gas price was lower than the natural gas floor prices, which ranged between $7.50 and $8.50 per Mcf. For the 2008 Fiscal Year, the settlements paid by us were cumulative monthly payments we made to our counterparty since the NYMEX crude oil price was higher than the crude oil ceiling prices of $83 and $86 per barrel that expired on June 30, 2008, and for ceiling prices specified under our costless collars. Our commodity derivative agreements are discussed in greater detail in Note 5 to the consolidated financial statements.
Income Tax Benefit
For the 2008, 2007, and 2006 Fiscal Years, we recorded a deferred income tax benefit of $9.8 million, $1.9 million and $3.8 million, respectively. For the 2006 Fiscal Year, the $3.8 million benefit amounts to an effective tax rate of approximately 65%, due to recording the effect of a change in enacted rates in the State of Texas in May 2006, amounting to $1,840,000. See Note 11 to our consolidated financial statements for more information. The effective rate for both the 2008 and 2007 Fiscal Years was approximately 36%.
Income from Discontinued Operations
On June 11, 2007, pursuant to the terms of an Agreement for Purchase and Sale, we sold our interests in certain Rich Valley properties located in Oklahoma and Kansas ("Rich Valley Properties") to Anadarko Minerals, Inc. for net proceeds of $6.9 million cash. The sale of the Rich Valley Properties resulted in a pre-tax gain of $3.8 million. For the 2007 Fiscal Year, we recognized income from the discontinued operations of $2.6 million. For the 2008 Fiscal Year, we recognized a loss from discontinued operations of $49,000 due to the payment of Oklahoma sales taxes on the sale of these properties. The sale is discussed in greater detail at Note 6 to the consolidated financial statements.
Preferred Stock Dividend
For the 2008 and 2007 Fiscal Years, we incurred $4.1 million and $3.2 million respectively, of Preferred Stock dividends as a result from the Preferred Stock financing, which was completed on September 6, 2006, as discussed in Note 2 to the consolidated financial statements and above under "Liquidity and Capital Resources-September 2006 Financing." 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. We did not have Preferred Stock dividends during the 2006 Fiscal Year.
Contractual Obligations
The following table sets forth our contractual obligations in thousands at June 30, 2008 for the periods shown:
(1)The senior and subordinated credit agreements mature on November 29, 2009 and March 17, 2011, respectively. On July 1, 2008, as discussed in Note 2 to the consolidated financial statements, we paid down $54.0 million on the senior credit agreement to reduce the long-term debt balance to $19.5 million. At September 8, 2008, there was $28.7 million combined long-term debt outstanding under the two credit agreements. 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 June 30, 2008, our results of operations were impacted by the $23.8 million unrealized loss on commodity derivatives. This resulted from significant price increases for both oil
and natural gas during the quarter ended June 30, 2008 which increased our derivative liabilities due under our commodity derivatives at June 30, 2008.
Critical Accounting Policies
We have identified the critical accounting policies used in the preparation of our financial statements. These are the accounting policies that we have determined involve the most complex or subjective decisions or assessments.
We prepared our consolidated financial statements in accordance with United States generally accepted accounting principles ("GAAP"). GAAP requires management to make judgments and estimates, including choices between acceptable GAAP alternatives.
Oil and Natural Gas Properties and Equipment
We follow the successful efforts method of accounting. All developmental costs are capitalized. We are predominately engaged in the acquisition and development of proved reserves as opposed to exploration activities. The property costs reflected in the accompanying consolidated balance sheets resulted from acquisitions and development activity. Capitalized overhead costs that directly relate to our drilling and development activities were $0.8 million and $0.5 million, for the years ended June 30, 2008 and 2007, respectively. We recorded capitalized interest costs of $2.5 million and $0.3 million for the years ended June 30, 2008 and 2007, respectively. We record capitalized interest for projects that have an expected cost of at least $1.5 million and a development period of at least six months.
Depreciation and depletion of producing properties is computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.
Our unit-of-production amortization rates are revised on a quarterly basis. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until proved reserves associated with the projects can be determined or until impairment occurs. As of June 30, 2008 and 2007, capitalized costs related to waterflood and ASP projects that are in process and not subject to depletion amounted to $47.6 million and $22.8 million, respectively.
At least quarterly, or more frequently if conditions indicate that long-term assets may be impaired, the carrying value of our properties is compared to management's future estimated pre-tax cash flow from the properties. If undiscounted cash flows are less than the carrying value, then the asset value is written down to fair value. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis. We had no significant unproved properties at June 30, 2008 or 2007. No impairment was necessary for the years ended June 30, 2008, 2007 or 2006.
Estimates of Proved Reserves
The term proved reserves is defined by the Securities and Exchange Commission in
Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, increasing net loss. A decline in
estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil and natural gas actually produced.
Asset Retirement Obligation
Our financial statements reflect the fair value for any asset retirement obligation that can be reasonably estimated. The retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations.
Revenue Recognition
We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering systems; therefore, we do not incur transportation costs related to our sales of oil and natural gas production.
As previously discussed, we sold our crude oil and natural gas production to several independent purchasers. During the year ended June 30, 2008, we had sales of 10% or more of our total revenues to four customers which represented 33%, 18%, 15% and 14% of total operating revenue, respectively. During the year ended June 30, 2007, we had sales of 10% or more of our total revenues to four customers which represented 36%, 18%, 17% and 16% of total operating revenue, respectively. During the year ended June 30, 2006, we had sales to primarily five customers which represented 29%, 25%, 12%, 12% and 10% of total operating revenue, respectively.
Stock-Based Compensation Expense
We account for share-based payment arrangements with employees and directors at their grant-date fair value and record the related expense over the requisite service period.
Commodity Derivatives
We are required to hedge a portion of our production at specified prices for oil and natural gas under the senior and subordinated credit agreements, as discussed in Note 5 to the consolidated financial statements. The objective is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect the outstanding debt amounts and maximize the funds available under our existing credit agreements, which helps us to support our annual capital budgeting and expenditure plans. We have entered into commodity derivatives that involve "costless collars" and price floors for our crude oil and natural gas production. These derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets and are measured at fair value.
We do not designate our commodity derivatives as cash flow or fair value hedges. We do not hold or issue commodity derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our commodity derivatives. We anticipate, however, that our counterparties will be able to fully satisfy their obligations under the commodity derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts subject to credit risk and we monitor the credit standing of the counterparties.
Changes in the fair values of our derivative instruments are recorded immediately in earnings as unrealized gains or losses on commodity derivatives on our consolidated statements of operations. Cash flows resulting from the settlement of our derivative instruments are recorded as realized gains or losses on commodity derivatives on the consolidated statements of operations.
New Accounting Pronouncements
Statement of Financial Accounting Standards No. 157, Fair Value Measurements, ("SFAS No. 157") was issued by the Financial Accounting Standards Board ("FASB") in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 57 applies to other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of SFAS No. 157 will result in additional disclosure requirements. We will adopt SFAS No. 157 on July 1, 2008. We do not expect adoption of SFAS No. 157 will have a material impact on our financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115 ("SFAS No. 159). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. We will adopt SFAS No. 159 on July 1, 2008. We do not expect adoption of SFAS No. 159 will have a material impact on our financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS No. 141R"). Among other things, SFAS No. 141R establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. This standard will change our accounting treatment for business combinations on a prospective basis.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 ("SFAS No. 160"). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent's ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We do not expect the adoption of this statement will have a material impact on our financial position, results of operations or cash flows.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement 133 ("SFAS No. 161"). SFAS No. 161 amends
and expands SFAS No. 133 to enhance required disclosures regarding derivatives and hedging activities. It requires companies to provide additional disclosure to discuss the uses of derivative instruments; the accounting for derivative instruments and related hedged items under SFAS No. 133; and how derivative instruments and related hedged items affect the company's financial position, financial performance and cash flows. We will adopt SFAS No. 161 on July 1, 2009. We do not expect the adoption of this statement will have a material impact on our financial position, results of operations or cash flows.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Pursuant to our credit agreements, we are subject to risks associated with interest rate fluctuations, as described under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Agreements." During our fiscal year ended June 30, 2008, if there had been an increase in the interest rate of 1%, our total interest cost would have increased by $481,000 annually.
Commodity Risk
Our revenues are derived from the sale of our crude oil and natural gas production. The prices for oil and natural gas are extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Pursuant to our credit agreements discussed in Note 4 to the consolidated financial statements, we are required to enter into commodity derivative contracts to mitigate price risk on at least 50% and no greater than 85% of our crude oil and natural gas production attributable to PDP reserves for at least three years as of the end of each six month period. Therefore, for the hedged production, we will receive at least the floor prices.
Assuming that the prices that we receive for our crude oil and natural gas production are above the floor prices, based on our actual fiscal year sales volumes for the year ended June 30, 2008, a 10% decline in the prices we receive for our crude oil and natural gas production would have had an approximate $4.5 million impact on our revenues.
As a direct result of the subordinated credit agreement, we entered into "costless collar" financial contracts with UBOC as follows:
Prior to obtaining the subordinated debt, our financial contracts consisted of purchasing price floors. As of June 30, 2008, these financial contracts are summarized in the table below.
The total volumes covered by "costless collars" and price floors detailed in the above tables are greater than 85% of our crude oil and natural gas production volumes attributable to PDP reserves for at least three years. The lenders under our senior and subordinated credit agreements have approved all commodity derivative contracts.
We computed our mark-to-market valuations used for our commodity derivatives based on assumptions regarding forward prices, volatility and the time value of money. We compared our valuations to our counterparties' valuations to further validate our mark-to-market valuations. During the years ended June 30, 2008, 2007 and 2006, we recognized unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $29.4 million, $1.8 million and $3.2 million, respectively. Of the $29.4 million amount for the year ended June 30, 2008, $26.5 million pertained to the costless collars, which did not require any initial cash outlay and do not involve future cash outlay unless the NYMEX crude oil and natural gas prices exceed the ceiling prices as specified in the table above.
If crude oil prices fell $1 below our hedged crude oil price floor, we would have received approximately $430,000 annually due to having the crude oil price floor hedge in place. If natural gas prices fell $1 below our hedged natural gas price floor, we would have received approximately $1,907,000 annually due to having the natural gas price floor hedge in place.
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 the 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 provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is (i) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and (ii) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based on that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures as of June 30, 2008 were effective.
Management's Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Securities Exchange Act of 1934 Rule 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. 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 transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with 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, 2008, 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, 2008 to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.
Hein & Associates LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued an attestation report on the Company's internal control over financial reporting as of June 30, 2008. The report, dated September 8, 2008, which expressed an opinion that the Company had maintained effective internal control over financial reporting as of June 30, 2008 based on criteria established in the COSO Framework, is included below.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Cano Petroleum, Inc.
Fort Worth, Texas
We have audited Cano Petroleum Inc.'s internal control over financial reporting as of June 30, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cano Petroleum Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Cano Petroleum, Inc. maintained, in all material respects, effective internal control over financial reporting as of June 30, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries as of June 30, 2008 and 2007, 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, 2008 and our report dated September 8, 2008 expressed an unqualified opinion.
HEIN & ASSOCIATES LLP
Dallas, Texas
September 8, 2008
Changes in Internal Controls
During the quarter ended June 30, 2008, 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 Proxy Statement relating to the 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 28, 2008, and that 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 Proxy Statement relating to the 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 28, 2008, and that 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 Proxy Statement relating to the 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 28, 2008, and that 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 Proxy Statement relating to the 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 28, 2008, and that will be incorporated herein by reference.
Item 14.
Item 14. Principal Accountant 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, 2008 and 2007 and (ii) audit committee's pre-approval policies and procedures for audit and non-audit services, will be set forth in the earlier filed of an amendment to this annual report on Form 10-K or our Proxy Statement relating to the 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to October 28, 2008, and that will be incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and 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, 2008 and 2007, Consolidated Statements of Operations for each of the three years in the period ended June 30, 2008, Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended June 30, 2008, Consolidated Statements of Cash Flows for each of the three years in the period ended June 30, 2008, 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.
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 Securities and Exchange Commission, granting unto said attorneys, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as full to all intents and purposes as he himself might or could do if personally present, thereby ratifying and confirming all that said attorneys-in-fact and agents, or either of them, or their or his substitute or substitutes, may lawfully do or cause to be done.
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
*Filed herewith. +Management contract or compensatory plan, contract or arrangement.
Item 8. Financial Statements
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Cano Petroleum, Inc.
Fort Worth, Texas
We have audited the consolidated balance sheets of Cano Petroleum, Inc. and subsidiaries (collectively, the "Company") as of June 30, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2008, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of June 30, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 8, 2008 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
HEIN & ASSOCIATES LLP
Dallas, Texas
September 8, 2008
CANO PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to these consolidated financial statements.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cano Petroleum, Inc. (together with its direct and indirect wholly-owned subsidiaries, "Cano," "we," "us," or the "Company") is an independent oil and natural gas company, based in Fort Worth, Texas, that is primarily utilizing waterflooding and enhanced oil recovery techniques to increase production and reserves at our existing properties and properties we may acquire in the future. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma. Our focus on domestic, mature oil fields eliminates exploration risk and the uncertainty of international development.
Consolidation and Use of Estimates
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and include the accounts of Cano and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which may affect the amount at which oil and natural gas properties are recorded. The computation of stock-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. Our liabilities and assets associated with commodity derivatives involve significant assumptions related to volatility and future prices for crude oil and natural gas. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems at our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil and natural gas actually produced.
Pro Forma Financial Information
We have presented unaudited pro forma financial information on our consolidated balance sheets and consolidated statements of changes in stockholders' equity, as of June 30, 2008, to present the effects of an equity issuance of approximately $54.0 million, which was finalized on July 1, 2008 as if the equity issuance had occurred on June 30, 2008. This is further discussed under Note 2. We do not believe the equity issuance, if it had occurred on June 30, 2008, would have had a material effect to our consolidated statements of operations.
Oil and Gas Properties and Equipment
We follow the successful efforts method of accounting. All developmental costs are capitalized. We are predominately engaged in the acquisition and development of proved reserves as opposed to exploration activities. The property costs reflected in the accompanying consolidated balance sheets
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
resulted from acquisitions and development activity. Capitalized overhead costs that directly relate to our drilling and development activities were $0.8 million and $0.5 million, for the years ended June 30, 2008 and 2007, respectively. We recorded capitalized interest costs of $2.5 million and $0.3 million for the years ended June 30, 2008 and 2007, respectively. We record capitalized interest for projects that have an expected cost of at least $1.5 million and a development period of at least six months.
Depreciation and depletion of producing properties is computed on the unit-of-production method based on estimated proved oil and natural gas reserves. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.
Our unit-of-production amortization rates are revised on a quarterly basis. Our development costs and lease and wellhead equipment are depleted based on proved developed reserves. Our leasehold costs are depleted based on total proved reserves. Investments in major development projects are not depleted until such project is substantially complete and producing or until an impairment occurs. As of June 30, 2008 and 2007, capitalized costs related to waterflood and alkaline-surfactant-polymer projects that are in process and not subject to depletion amounted to $47.6 million and $22.8 million, respectively.
At least quarterly, or more frequently if conditions indicate that long-term assets may be impaired, the carrying value of our properties is compared to management's future estimated pre-tax cash flow from the properties. If undiscounted cash flows are less than the carrying value, then the asset value is written down to fair value. Impairment of individually significant unproved properties is assessed on a property-by-property basis, and impairment of other unproved properties is assessed and amortized on an aggregate basis. We had no significant unproved properties at June 30, 2008 or 2007. No impairment was necessary for the years ended June 30, 2008, 2007 or 2006.
Asset Retirement Obligation
Our financial statements reflect the fair value for any asset retirement obligation, consisting of future plugging and abandonment expenditures related to our oil and gas properties, which can be reasonably estimated. The asset retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations.
Goodwill
The amount paid for certain acquisitions in excess of the fair value of the net assets acquired has been recorded as goodwill in the consolidated balance sheets. Goodwill is not amortized, but is assessed for impairment annually or whenever conditions would indicate impairment may exist. There were no impairments recorded for the years ended June 30, 2008, 2007 or 2006.
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 FDIC insurance limits.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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 indicated at June 30, 2008 or 2007. As of June 30, 2008, our accounts receivable were primarily with several independent purchasers of our crude oil and natural gas production. At June 30, 2008, we had balances due from five customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These five customers accounted for 29%, 17%, 15%, 14% and 13% of accounts receivable, respectively.
At June 30, 2007, we had balances due from four customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These four customers accounted for 26%, 26%, 25% and 10% of 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 customers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost customers.
Revenue Recognition
We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from those purchasers are collectible. The point of sale for our oil and natural gas production is at our applicable field gathering systems; therefore, we do not incur transportation costs related to our sales of oil and natural gas production.
As previously discussed, we sold our crude oil and natural gas production to several independent purchasers. During the year ended June 30, 2008, we had sales of 10% or more of our total revenues to four customers which represented 33%, 18%, 15% and 14% of total operating revenue, respectively. During the year ended June 30, 2007, we had sales of 10% or more of our total revenues to four customers representing 36%, 18%, 17% and 16% of total operating revenue, respectively. During the year ended June 30, 2006, we had sales to primarily five customers which represented 29%, 25%, 12%, 12% and 10% of total operating revenue, respectively.
In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative customers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost customers.
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
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
accounts receivable that pertains to us is recognized as operating revenue. The portion that pertains to certain working interest and royalty owners are recorded as oil and gas sales payable.
Inventory
Our inventory consists of unsold barrels of crude oil remaining in our storage tanks at the end of the period. We value these crude oil barrels based on the lower of market or our average production cost.
Income Taxes
Deferred tax assets or liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities. These balances are measured using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
On July 13, 2006, the Financial Accounting Standards Board ("FASB") released FIN 48, "Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement 109" ("FIN 48"). FIN 48 requires a company to evaluate and disclose material uncertain tax positions it has taken with various taxing jurisdictions. Any interest and penalties related to uncertain tax positions would be recorded as interest expense and general and administrative expense, respectively. We adopted FIN 48 on July 1, 2007. At the time of adoption and as of June 30, 2008, the adoption of FIN 48 did not materially affect our operating results, financial position, or cash flows. As of June 30, 2008, 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 2007.
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, 2008 and 2007. The carrying amount of long-term debt approximates market value due to the use of market interest rates.
Net Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Diluted net loss per common share is computed in the same manner, but also considers the effect of common stock shares underlying the following:
The shares of common stock underlying the stock options, warrants, Preferred Stock, PIK dividends and restricted shares, as shown in the preceding table, are not included in weighted average shares outstanding for the years ended June 30, 2008, 2007 or 2006 as their effects would be anti-dilutive.
At June 30, 2006, the 2,659,975 restricted shares pertain to shares held in escrow pursuant to the Management Stock Pool Agreement pending the achievement of certain employment and performance goals, as discussed under Note 9.
Stock-Based Compensation Expense
We account for share-based payment arrangements, with employees and directors, at their grant-date fair value and record the related expense over the requisite service period.
Commodity Derivatives
We are required to hedge a portion of our production at specified prices for oil and natural gas under the senior and subordinated credit agreements, as discussed in Note 5. The objective is to reduce our exposure to declining commodity prices. By locking in minimum prices, we protect the outstanding debt amounts and maximize the funds available under our existing credit agreements, which helps us to support our annual capital budgeting and expenditure plans. We have entered into commodity derivatives that involve "costless collars" and price floors for our crude oil and natural gas production. These derivatives are recorded as derivative assets and liabilities on our consolidated balance sheets and are measured at fair value.
We do not designate our commodity derivatives as cash flow or fair value hedges. We do not hold or issue commodity derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our commodity derivatives. We anticipate, however, that our counterparties will be able to fully satisfy their obligations under the commodity derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts subject to credit risk and we monitor the credit standing of the counterparties.
Changes in the fair values of our derivative instruments are recorded immediately in earnings as unrealized gains or losses on commodity derivatives on our consolidated statements of operations. Cash flows resulting from the settlement of our derivative instruments are recorded as realized gains or losses on commodity derivatives on the consolidated statements of operations.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements
Statement of Financial Accounting Standards No. 157, Fair Value Measurements, ("SFAS No. 157") was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 57 applies to other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of SFAS No. 157 will result in additional disclosure requirements. We will adopt SFAS No. 157 on July 1, 2008. We do not expect adoption of SFAS No. 157 will have a material impact on our financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115 ("SFAS No. 159"). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. We will adopt SFAS No. 159 on July 1, 2008. We do not expect adoption of SFAS No. 159 will have a material impact on our financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS No. 141R"). Among other things, SFAS No. 141R establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. This standard will change our accounting treatment for business combinations on a prospective basis.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 ("SFAS No. 160"). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent's ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We do not expect the adoption of this statement will have a material impact on our financial position, results of operations or cash flows.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement 133 ("SFAS No. 161"). SFAS No. 161 amends and expands SFAS No. 133 to enhance required disclosures regarding derivatives and hedging activities. It requires companies to provide additional disclosure to discuss the uses of derivative instruments; the accounting for derivative instruments and related hedged items under SFAS No. 133; and how derivative instruments and related hedged items affect the company's financial position, financial performance and cash flows. We will adopt SFAS No. 161 on July 1, 2009. We do not expect the
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
adoption of this statement will have a material impact on our financial position, results of operations or cash flows.
2. PREFERRED AND COMMON STOCK FINANCINGS
Pro Forma Balance Sheet-Common Issuance Completed July 1, 2008
On July 1, 2008, we completed the sale of 7,000,000 shares of our common stock through an underwritten offering at a share price of $8.00 per share ($7.75 net to us) resulting in net proceeds of approximately $54.0 million after underwriting discounts and commissions and expenses.
We used the net proceeds from the offering to pay down debt which will subsequently be drawn in order to finance (i) existing development activities in certain core areas such as the Panhandle and Cato properties, (ii) selective acquisitions and (iii) general corporate purposes.
The pro forma balance sheet information presented as part of our consolidated balance sheets reflects the application of proceeds received on July 1, 2008 totaling approximately $54.0 million to paydown long-term debt. Accordingly, long-term debt is reduced by approximately $54.0 million, and common stock and additional paid-in capital, combined, are increased by the $54.0 million. Our pro forma information also includes a reclassification of $0.3 million of deferred offering costs incurred at June 30, 2008 from "fixed assets and other" to additional paid-in capital. We presented pro forma information on our consolidated balance sheets and statements of changes in stockholders' equity to reflect this common stock issuance as if it occurred on June 30, 2008.
Private Placement
On November 7, 2007, we sold in a private placement 3.5 million shares of our common stock at $7.15 per share for net proceeds of $23.4 million after deducting issuance costs of $1.6 million. The net proceeds were used to pay down our long-term debt due under our senior credit agreement.
In connection with the private placement, we entered into a registration rights agreement with the purchasers in such private placement which required us to file the registration statement within a certain period of time and have it declared effective within a certain period of time. We met both of these deadlines. However, if we are not able to maintain the effectiveness of the registration statement, subject to certain limitations, we will have to pay 1.0% of the aggregate purchase price of the securities purchased in the private placement on the first day of such initial maintenance failure and on each 30th day after the day of such initial maintenance failure (prorated for periods totaling less than 30 days), with the maximum aggregate registration delay payments being 10% of the aggregate purchase price. We do not believe it is probable we will incur any penalties under this provision and accordingly have not accrued any loss.
Warrants
As discussed below under "September 2006 Financing", we had outstanding warrants for the purchase of 1,646,061 common shares at an exercise price of $4.79 per share that were to expire on March 6, 2008. The warrants were exercised as follows:
•1,084,345 warrants were exercised for cash for which we received $5.2 million for the issuance of 1,084,345 common shares.
CANO PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. PREFERRED AND COMMON STOCK FINANCINGS (Continued)
•561,291 warrants were exercised in a cashless manner for the issuance of 144,506 common shares.
•425 warrants were not exercised and expired pursuant to their terms.
As of June 30, 2008, we no longer have any outstanding warrants.
September 2006 Financing
On September 6, 2006, we sold in a private placement 49,116 shares of Series D Convertible Preferred Stock ("Preferred Stock") at a price of $1,000.00 per share and 6,584,247 shares of common stock at a price of $4.83 per share, the three day average closing price of the stock prior to the execution of the definitive agreements, plus a warrant component. The Preferred Stock has a 7.875% dividend and features a paid-in-kind ("PIK") provision that allows, at the investor's option, the investor to receive additional shares of common stock upon conversion for the dividend in lieu of a cash dividend payment. Holders of approximately 55% of the Preferred Stock chose the PIK dividend option. The Preferred Stock is convertible to common stock at a price of $5.75 per share and the common stock was subject to 25% warrant coverage at an exercise price of $4.79 per share. The warrant component provided for the purchase of 1,646,061 common shares and expired on March 6, 2008, as previously discussed. 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. Gross proceeds from the transactions were $80.9 million, of which $49.1 million was attributable to the Preferred Stock, and $31.8 million was attributable to the common stock and warrants. Net proceeds were $75.5 million after deducting issuance costs of $5.4 million.
Cash proceeds from the September 2006 financing were used to repay long-term debt (see Note 4), for general corporate purposes and to fund our capital expenditures development.
In connection with the September 2006 financing, we were required to file a registration statement on Form S-1 with the SEC registering the resale of the common stock issued in the September 2006 financing and the common shares underlying the Preferred Stock and the warrants, which was filed on October 13, 2006 and was declared effective on January 4, 2007. On April 9, 2007, we also filed to register these same common shares on a registration statement on Form S-3, which was declared effective on April 19, 2007. We are required to maintain the effectiveness of the registration statement until such common shares may be resold pursuant to Rule 144(k) under the Securities Act of 1933, as amended, or all such common shares have been resold subject to certain exceptions, and if the 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.
Pursuant to the terms of the Preferred Stock and subject to certain exceptions, if we issue or sell common stock at a price less than the conversion price (currently $5.75 per share) in effect immediately prior to such issuance or sale, the conversion price shall be reduced. If such an issuance is made on or after June 6, 2007, the conversion price will be lowered to the issue or sale price. The above described adjustment is not triggered by issuances or sales involving the following: (i) shares issued in connection with an employee benefit plan; (ii) shares issued upon conversion of our Preferred
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. PREFERRED AND COMMON STOCK FINANCINGS (Continued)
Stock; (iii) shares issued upon exercise of the warrants issued on September 6, 2006; (iv) shares issued in connection with a firm commitment underwritten public offering with gross proceeds in excess of $50,000,000; (v) shares issued in connection with any strategic acquisition or transaction; (vi) shares issued in connection with any options or convertible securities that were outstanding on August 25, 2006; or (vii) shares issued in connection with any stock split, stock dividend, recapitalization or similar transaction.
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 owing on such share prior to any payments being made to any class of capital stock ranking junior on liquidation to the Preferred Stock.
The issuance of Preferred Stock is accounted for as temporary equity since the holder can request redemption for cash under certain circumstances.
For the twelve months ended June 30, 2008, the preferred dividend was $4.1 million, of which $2.1 million pertained to holders of the PIK dividend option. For the twelve months ended June 30, 2007, the preferred dividend was $3.2 million, of which $1.7 million pertained to holders of the PIK dividend option.
At June 30, 2008, the cumulative PIK dividend amounted to $3.9 million, which converts into 674,569 shares of our common stock.
3. PREFERRED STOCK CONVERSIONS
On October 17, 2007, 2,000 shares of our Preferred Stock were converted into 349,119 shares of our common stock. The issued common shares consisted of 347,826 shares based on the $5.75 conversion price of the Preferred Stock and 1,293 shares in lieu of the accrued but unpaid dividends from October 1, 2007 to October 17, 2007 pursuant to the terms of the Preferred Stock.
On December 4, 2007, 2,000 shares of our Preferred Stock were converted into 352,772 shares of our common stock. The issued common shares consisted of 347,826 shares based on the $5.75 conversion price of the Preferred Stock and 4,946 shares in lieu of the accrued but unpaid dividends from October 1, 2007 to December 4, 2007 pursuant to the terms of the Preferred Stock.
On January 8, 2008, 575 shares of our Preferred Stock were converted into 100,175 shares of our common stock. The issued common shares consisted of 100,000 shares based on the $5.75 conversion price of the Preferred Stock and 175 shares in lieu of the accrued but unpaid dividends from January 1, 2008 to January 8, 2008 pursuant to the terms of the Preferred Stock.
On June 20, 2008, 67 shares of our Preferred Stock were converted into 11,859 shares of our common stock. The issued common shares consisted of 11,652 shares based on the $5.75 conversion
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. PREFERRED STOCK CONVERSIONS (Continued)
price of the Preferred Stock and 207 shares in lieu of the accrued but unpaid dividends from April 1, 2008 to June 20, 2008 pursuant to the terms of the Preferred Stock.
At June 30, 2008, there were 44,474 shares of our Preferred Stock outstanding.
4. LONG-TERM DEBT
At June 30, 2008, our total outstanding long-term debt was $73.5 million, which consisted of $58.5 million due under the senior credit agreement and $15.0 million due under the subordinated credit agreement. At June 30, 2008 and 2007, the weighted average interest rate for the two agreements was 6.33% and 7.46%, respectively. As discussed under Note 2, we received $54.0 million from the sale of common stock completed on July 1, 2008. The pro forma balance sheet information presented as part of our consolidated balance sheets reflects the use of the $54.0 million proceeds to paydown outstanding debt under the senior credit agreement, which reduced the long-term debt balance to $19.5 million at July 1, 2008. The senior and subordinated credit agreements are discussed in greater detail below.
Senior Credit Agreement
On November 29, 2005, we entered into a $100 million senior credit agreement with lenders led by Union Bank of California, N.A. ("UBOC"), as administrative agent and as issuing lender. Pursuant to the terms of the senior credit agreement, a borrowing base based on our proved reserves is redetermined every six months with one optional redetermination allowed between scheduled redeterminations. On September 7, 2007, the lenders approved the borrowing base amount of $60.0 million, which remained unchanged at June 30, 2008. As of June 30, 2008, the unused borrowing base commitment was $1.5 million. As a result of the previously discussed $54.0 million paydown on July 1, 2008, the unused borrowing base commitment was $55.5 million as of July 1, 2008. As of September 8, 2008, the unused commitment was $46.3 million.
The outstanding principal is due on or before November 29, 2009 unless, pursuant to the terms of the senior credit agreement, specific events of default occur as a result of which all outstanding principal and all accrued interest may be accelerated. Such specific events of default, include, but are not limited to: payment defaults; breaches of representations and warranties, and covenants; insolvency; a "change of control" in our ownership as described in the senior credit agreement; and a "material adverse change" as described in the senior credit agreement.
Subject to certain restrictions, the senior credit agreement permits the issuance of convertible notes and equity. If we are not in default under the senior credit agreement, we may make interest payments on any convertible notes and dividend payments on any preferred equity securities.
The senior credit agreement requires us to comply with certain credit metrics, such as certain ratios of debt to EBITDA (as defined in the senior credit agreement), current assets to current liabilities, and EBITDA to interest. Each metric is further defined below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT (Continued)
The leverage ratio is as follows: (a) for each fiscal quarter ending prior to December 31, 2008, the ratio of (i) Consolidated Debt (as defined in the senior credit agreement) to (ii) consolidated EBITDA for the four fiscal quarter period then ended must not be greater than 5.00 to 1.00; (b) at the end of each fiscal quarter ending on or after December 31, 2008 but prior to June 30, 2009, the ratio shall not be greater than 4.50 to 1.00; and (c) at the end of each fiscal quarter ending on or after June 30, 2009, the ratio shall not be greater than 4.00 to 1.00. For the purposes of calculating the leverage ratio, the definition of "Consolidated Debt" shall not include "Debt" outstanding under Preferred Stock as discussed in Note 2. Amendment No. 12, effective as of June 30, 2008, permitted us to reduce Consolidated Debt by the $54.0 million of proceeds from the sale of common stock previously discussed in Notes 2 and 4 in order to compute the leverage ratio at June 30, 2008. We were in compliance with the leverage ratio as of June 30, 2008.
The current ratio specifies that the ratio of (i) current assets to (ii) current liabilities must not be less than 1:00 to 1:00 for each financial quarter. For purposes of computing the current ratio, current assets and liabilities arising from SFAS Nos. 133 and 143 shall be excluded. The definition of current assets includes un-borrowed amounts under our borrowing base. Amendment No. 11, dated as of June 27, 2008, permits us to increase the unborrowed amount under the borrowing base by the $54.0 million of proceeds from the sale of common stock previously discussed in Note 2 in order to compute the current ratio at June 30, 2008. We were in compliance with the current ratio as of June 30, 2008.
The interest coverage ratio is the ratio of our consolidated EBITDA for the four fiscal quarter period then ended to our consolidated Interest Expense for the four fiscal quarters then ended must be at least 2.00 to 1.00. The definition of "Interest Expense" shall include cash dividends paid under our Preferred Stock, but shall exclude PIK (non-cash) dividends under Preferred Stock, as discussed in Note 2. We were in compliance with the interest coverage ratio as of June 30, 2008.
At our option, the interest rate is computed based on either (i) on the prime rate plus the applicable margin ranging up to 1.00% based on the utilization level or (ii) on the LIBOR rate applicable to the interest period plus the applicable margin ranging from 1.75% to 2.50% based on the utilization level. At June 30, 2008 and 2007, the interest rate was 5.76% and 7.46%, respectively. For loans that are three months or less in maturity, interest is due on the maturity date of such loan. For loans that are in excess of three months, interest is due every three months.
The senior credit agreement imposes certain restrictions on us and our subsidiaries, subject to specific exceptions, including, but not limited to, the following: (i) incurring additional liens; (ii) incurring additional debt; (iii) merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property; (iv) making certain payments, including cash dividends to our 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 interests in any person or any oil and natural gas properties or activities related to oil and natural gas properties unless with regard to new oil and natural gas properties, such properties are mortgaged to UBOC, as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage in favor of UBOC, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT (Continued)
In addition, we are required to hedge our exposure to commodity price risk associated with expected oil and natural gas production. The senior credit agreement requires the hedges to cover no less than 50% and no greater than 85% of our crude oil and natural gas production attributable to proved developed producing reserves for at least three years as of the end of each six month period. Our commodity derivatives are further discussed in Note 5.
As security for our obligations under the senior credit agreement: (i) eight of our subsidiaries have guaranteed all of our obligations; (ii) we, together with eight of our subsidiaries, have executed mortgages in favor of UBOC, as collateral trustee, covering oil and natural gas properties located in Texas, Oklahoma and New Mexico; (iii) we, together with eight of our subsidiaries, have granted a security interest in favor of UBOC, as collateral trustee, in substantially all of our assets; and (iv) we and two subsidiaries have pledged our ownership interests in eight of our subsidiaries to UBOC, as collateral trustee.
Subordinated Credit Agreement
On March 17, 2008, we entered into a $25.0 million subordinated credit agreement with UnionBanCal Equities, Inc. ("UBE") as the administrative agent. The initial amount available for borrowing of $15.0 million was drawn on March 18, 2008 and used to reduce the outstanding amount under our senior credit agreement. Pursuant to the terms of the subordinated credit agreement, we may request additional borrowings of up to $10.0 million with the lenders determining in their own discretion whether to permit such additional borrowings. Any additional borrowings must be used to reduce the outstanding amount under the senior credit agreement.
At our option, the interest rate is computed based on either (i) the prime rate plus the applicable margin of (a) 4.75% if the Consolidated Debt (as defined in the subordinated credit agreement) to consolidated EBITDA (as defined in the subordinated credit agreement) ratio is less than or equal to 4.00 to 1.00 or (b) 5.00% if the Consolidated Debt to consolidated EBITDA ratio is greater than 4.00 to 1.00 or (ii) the LIBOR rate plus the applicable margin of (a) 5.75% if the Consolidated Debt to consolidated EBITDA ratio is less than or equal to 4.00 to 1.00 or (b) 6.00% if the Consolidated Debt to consolidated EBITDA ratio is greater than 4.00 to 1.00. At June 30, 2008, the interest rate was 8.56% based on LIBOR plus 5.75%. If the interest rate is based on the prime rate, interest payments are due quarterly, and if the interest rate is based on the LIBOR rate, interest payments are due every three months.
Unless specific events of default occur, the maturity date is March 17, 2011, subject to our right to request up to two extensions of one year each with the lenders determining in their own discretion whether to permit such extensions. Specific events of default which could cause all outstanding principal and accrued interest to be accelerated, include, but are not limited to, payment defaults, breaches of representations and warranties and covenants by us, certain cross-defaults, insolvency, a change in control or a material adverse change (as both terms are defined in the subordinated credit agreement). All unpaid principal and interest amounts are due at maturity.
The subordinated credit agreement contains certain negative covenants for us including, but not limited to, covenants, subject to certain exceptions, against the following: (i) incurring additional liens, (ii) incurring additional debt; (iii) merging or consolidating or selling, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. LONG-TERM DEBT (Continued)
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.
We must also comply with certain financial ratios as previously described under the "Senior Credit Agreement." The current ratio must not be less than 1.00 to 1.00 for each fiscal quarter. Amendment No. 1 dated as of June 27, 2008, permits us to increase the current assets by the $54.0 million of proceeds from the sale of common stock previously discussed in Note 2 in order to compute the current ratio at June 30, 2008. The leverage ratio must not be greater than 5.00 to 1.00. Amendment No. 2 dated as of June 30, 2008, permits us to reduce consolidated Debt (as defined in the subordinated credit agreement) by the $54.0 million of proceeds from the sale of common stock previously discussed in Note 2 in order to compute the leverage ratio at June 30, 2008.The interest coverage ratio must not be less than 1.50 to 1.00. The subordinated credit agreement also specifies that the ratio of Total Present Value (as defined in the subordinated credit agreement) to Consolidated Debt must not be less than 1.50 to 1.00. We were in compliance with these ratios as of June 30, 2008.
In addition, we are required to maintain the current hedges as summarized in Note 5 until their stated maturity and, unless otherwise agreed by the lenders, we are required to maintain hedges covering at least 50% and no greater than 85% of our crude oil and natural gas production attributable to proved developed producing reserves for at least three years as of the end of each six month period.
As security for our obligations under the subordinated credit agreement: (i) eight of our subsidiaries have guaranteed all of our obligations; (ii) we, together with eight of our subsidiaries, have executed mortgages covering oil and natural gas properties located in Texas, Oklahoma and New Mexico; (iii) we, together with eight of our subsidiaries, have granted a security interest in substantially all of our assets; and (iv) we and two subsidiaries have pledged our ownership interests in eight of our subsidiaries.
5. COMMODITY DERIVATIVES
Pursuant to our credit agreements discussed in Note 4, we are required to enter into commodity derivative contracts to mitigate price risk on at least 50% and no greater than 85% of our crude oil and natural gas production volumes attributable to proved, producing reserves, for at least three years
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. COMMODITY DERIVATIVES (Continued)
as of the end of each six month period ending thereafter. As a direct result of the subordinated credit agreement, we entered into "costless collar" financial contracts with UBOC as follows:
Prior to obtaining the subordinated debt, our financial contracts consisted of purchasing price floors. As of June 30, 2008, these financial contracts are summarized in the table below.
The total volumes covered by costless collars and price floors detailed in the above tables is greater than 85% of our crude oil and natural gas production volumes attributable to proved developed producing reserves through December 2010. The lenders under our senior and subordinated credit agreements have approved all commodity derivative contracts.
During the years ended June 30, 2008, 2007 or 2006, there were settlements under our commodity derivatives due to us and paid by us with our counterparty that are accrued as realized gains or losses on commodity derivatives in our consolidated statements of operations that are summarized as follows:
The cash settlements received by us 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 period. The cash settlements paid/accrued by us were cumulative monthly payments due to our
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. COMMODITY DERIVATIVES (Continued)
counterparty since the NYMEX crude oil and/or natural gas prices were higher than the "ceiling prices" set for the respective time period. 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. At June 30, 2008, we had amounts payable to our counterparty of $1.2 million, included in accounts payable on our consolidated balance sheet. At June 30, 2007, we had amounts due from our counterparty of $0.1 million, included in accounts receivable on our consolidated balance sheet.
We computed our mark-to-market valuations used for our commodity derivatives based on assumptions regarding forward prices, volatility and the time value of money. We compared our valuations to our counterparties' valuations to further validate our mark-to-market valuations. During the years ended June 30, 2008, 2007 and 2006, we recognized unrealized loss on commodity derivatives in our consolidated statements of operations amounting to $29.4 million, $1.8 million and $3.2 million, respectively. Of the $29.4 million amount for the year ended June 30, 2008, $26.5 million pertained to the costless collars, which did not require any initial cash outlay and do not involve future cash outlay unless the NYMEX crude oil and natural gas prices exceed the ceiling prices as specified in the table above.
6. DISCONTINUED OPERATIONS
On June 11, 2007, pursuant to the terms of an Agreement for Purchase and Sale, we sold our interests in the Rich Valley Properties located in Oklahoma and Kansas to Anadarko Minerals, Inc. for net proceeds of $6.8 million. The agreement had an effective date of April 1, 2007. The funds received were used to reduce the outstanding long-term debt as discussed in Note 4.
The results of operations of the Rich Valley Properties, effective April 1, 2007, have been presented as discontinued operations in the accompanying consolidated statements of operations. Prior year results have also been reclassified to report the results of operations of the Rich Valley Properties
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. DISCONTINUED OPERATIONS (Continued)
sold as discontinued operations. Results for these assets reported as discontinued operations were as follows:
Interest expense, net of interest income, was allocated to discontinued operations based on the percent of operating revenues applicable to discontinued operations to the total operating revenues.
As of April 1, 2007, the assets of the Rich Valley Properties totaled $3.3 million, of which $3.2 million represented the oil and gas properties, net. At June 30, 2006, the Rich Valley Properties' assets totaled $3.4 million, of which $3.2 million represented oil and gas properties, net.
7. RELATED PARTY TRANSACTIONS
On March 29, 2005, we entered into an agreement with Haddock Enterprises, LLC and Kenneth Q. Carlile (predecessor to Carlile Management, LLC) to explore the possibility of converting the Sabine Royalty Trust from a liquidating asset into a vehicle to acquire low risk assets. Each of the three parties owned a one-third interest in Sabine Production Operating, LLC ("Sabine Production"). Gerald W. Haddock is President of Haddock Enterprises, LLC and is a member of our Board of Directors. From inception through of June 30, 2006, we had incurred approximately $420,000 pertaining to the joint venture, of which $325,000 was funded directly to Sabine Production. During the year ended June 30, 2006, we incurred $380,000, which we charged to general and administrative expense.
On January 26, 2007 but effective January 8, 2007, we entered into an amendment to the agreement that provided that the maximum amount to be committed to Sabine Production by any member was increased from $325,000 to $375,000. The amendment also provided that after funding the increased commitment of $375,000, a member may withdraw as a member of Sabine Production. Upon a withdrawal, the withdrawing member forfeits its membership interests in Sabine Production and is released from all of its obligations under the agreement. On January 26, 2007, we made our final
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. RELATED PARTY TRANSACTIONS (Continued)
contribution of $50,000 to Sabine Production such that our aggregate contribution was $375,000 and on February 1, 2007, we delivered our notice of withdrawal from Sabine Production effective on February 1, 2007.
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 are able to provide fishing and outdoor opportunities for children with cancer, children from abusive family situations and children of military veterans. During the years ended June 30, 2008, 2007 and 2006, we paid $150,000, $150,000 and $125,000, respectively, to R.C. Boyd Enterprises, the owner of Honey Hole All Outdoors. Randall Boyd is the sole shareholder of R.C. Boyd Enterprises and is a member of our Board of Directors. Pursuant to a new agreement dated as of December 5, 2007, after December 31, 2008, we will no longer be a Honey Hole Production sponsor. Our remaining commitment from July 1, 2008 to December 31, 2008 is $75,000 ($37,500 per quarter). We are entitled to receive two thirty-second commercials during all broadcasts of the Honey Hole Production and receive opening and closing credits on each episode.
8. STOCK OPTION PLANS
We have granted stock options to key employees and outside directors as discussed below.
Prior to our 2005 Long-Term Incentive Plan
On December 16, 2004, we issued stock options for 50,000 shares of our common stock to Gerald Haddock, a current member of our board of directors, in exchange for certain financial and management consulting services at an exercise price of $4.00 per share. The options are exercisable at any time, in whole or in part, during the life of the option which expires on June 15, 2015.
On April 1, 2005, we adopted the 2005 Directors' Stock Option Plan ("Plan"). On April 1, 2005, pursuant to the Plan, we granted stock options to our five non-employee directors to each purchase 25,000 shares of common stock at an exercise price of $4.13 per share. The options vested on April 1, 2006, and expire on April 1, 2015. As of June 30, 2008, 50,000 options shares were exercised, 25,000 option shares were forfeited and the outstanding vested options totaled 50,000 shares.
On September 16, 2005, we granted stock options to James K. Teringo, Jr., then our Senior Vice President, General Counsel and Corporate Secretary to purchase 50,000 shares of common stock at an exercise price of $3.98 per share. These options were forfeited in May 2007.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. STOCK OPTION PLANS (Continued)
2005 Long-Term Incentive Plan
On December 7, 2005, our stockholders approved our 2005 Long-Term Incentive Plan ("2005 LTIP") that authorized the issuance of up to 1,000,000 shares of our common stock to key employees, key consultants and outside directors of our company and subsidiaries. On December 28, 2006, our stockholders approved an amendment to the 2005 LTIP that increases the number of shares authorized for issuance from 1,000,000 to 3,500,000 shares of our common stock. The amendment also increases for Executive Officers (as defined in the Plan) for any calendar year (i) the maximum number of stock options or stock appreciation rights that any Executive Officer can receive from 100,000 shares of common stock to 300,000 shares of common stock, (ii) the 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 from 100,000 shares of common stock to 300,000 shares of common stock; and (iii) the maximum number of shares relating to all awards that an Executive Officer can receive from 100,000 to 300,000. The 2005 LTIP permits the grant of incentive stock options, non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, dividend equivalent rights and other awards, whether granted singly, or in combination or in tandem. The 2005 LTIP terminates on December 7, 2015; however, awards granted before that date will continue to be effective in accordance with their terms and conditions.
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.
A summary of options we granted during the years ended June 30, 2008, 2007 and 2006 are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. STOCK OPTION PLANS (Continued)
The following is a summary of stock options outstanding at June 30, 2008:
Based on our $7.94 stock price at June 30, 2008, the intrinsic value of the options outstanding and exercisable was $2.4 million and $1.2 million, respectively.
Total options exercisable at June 30, 2008 amounted to 561,803 shares and had a weighted average exercise price of $5.75. Upon exercise, we issue the full amount of shares exercisable per the terms of the options from new shares. We have no plans to repurchase those shares in the future.
The following is a summary of options exercisable at June 30, 2008, 2007 and 2006:
The fair value of each stock option is estimated on the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on historical volatility of our common stock. We use historical data to estimate option exercise and employee termination within the valuation model. The expected lives of options granted represent the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the five-year U.S. Treasury yield curve in effect at the time of grant. The expected dividend yield reflects our intent not to pay dividends on our common stock during the contractual periods.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. STOCK OPTION PLANS (Continued)
The fair values of options granted along with the factors used to calculate the fair values of those options are summarized in the table below:
For the years ended June 30, 2008, 2007 and 2006, we have recorded a charge to stock compensation expense of $1.2 million, $0.6 million and $0.5 million, respectively, for the estimated fair value of the options granted to our directors and employees. As of June 30, 2008, total compensation cost related to non-vested awards not yet recognized amounted to $1.4 million, and we expect to recognize that amount over the remaining requisite service periods of the related awards up to three years.
9. RESTRICTED STOCK
Management Stock Pool Agreement
Pursuant to the terms of a Management Stock Pool Agreement dated May 28, 2004, the 5,165,000 shares issued to the Davenport Field Unit shareholders were placed in escrow, and were scheduled to be released from escrow pursuant to the achievement of certain employment and performance goals. Based on the final achievement of these goals, 3,896,706 shares were released to the Davenport Field Unit shareholders and 1,268,294 shares were returned as treasury shares.
Once the Board made its final determination of the performance shares awarded in October 2006, the Management Stock Pool Agreement expired and had no effect to the financial statements for the years ended June 30, 2008 or 2007.
Contingently Issued Shares from the 2005 Long-Term Incentive Plan
During June 2006, 140,000 restricted shares were issued to key employees from our 2005 LTIP, previously discussed in Note 8. On July 2, 2007, we granted our executive officers restricted stock for services provided during the year ended June 30, 2007 totaling 395,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of July 2, 2007.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. RESTRICTED STOCK (Continued)
On May 12, 2008, we granted our executive officers restricted stock for services provided during the year ended June 30, 2008 totaling 460,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of May 12, 2008. On June 23, 2008, in connection with his hiring, we granted an executive officer restricted stock totaling 100,000 shares with the restrictions on transfer lapsing for one-third of the shares on the first, second and third anniversaries of June 23, 2008. A summary of non-vested restricted share activity for the two years ended June 30, 2008 and 2007 is as follows:
The restricted shares will vest to the individual employees based on future years of service ranging from one to three years depending on the life of the award agreement. The fair value is based our actual stock price on the date of grant multiplied by the number of restricted shares granted. As of June 30, 2008 and 2007, the value of non-vested restricted shares amounted to $6.8 million and $0.5 million, respectively. In accordance with SFAS No. 123(R), for the years ended June 30, 2008, 2007 and 2006, we have expensed $1.7 million, $0.2 million and $0, respectively, to stock compensation expense based on amortizing the fair value over the appropriate service period.
10. 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, 2008, our liability for ARO was $3.4 million, of which $3.1 million was considered long term. At June 30, 2007, our liability for ARO was $2.4 million, of which $2.1 was considered long term. Our asset retirement obligations are recorded as current or non-current liabilities based on the estimated timing of the related cash flows. For the years ended June 30, 2008, 2007, and 2006, we have recognized accretion expense, net of discontinued operations discussed in Note 6, of $0.2 million, $0.1 million and $0.1 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. ASSET RETIREMENT OBLIGATION (Continued)
The following table describes the changes in our asset retirement obligations for the years ended June 30, 2008 and 2007 (in thousands):
For the year ended June 30, 2008, the change in estimate resulted primarily from an increase in estimated costs to plug and abandon wells. For the year ended June 30, 2007, the change in estimate resulted primarily from an increase in productive years for certain fields.
11. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax provisions. Our income tax expense (benefit) is as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. INCOME TAXES (Continued)
A reconciliation of the differences between our applicable statutory tax rate and our effective income tax rate for the years ended June 30, 2008, 2007 and 2006 is as follows:
A schedule showing the significant components of the net deferred tax liability as of June 30, 2008 and 2007 are as follows:
In May 2006, the State of Texas enacted legislation for a Texas margin tax which restructured the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new "taxable margin" component. As the tax base for computing Texas margin tax is derived from an income-based measure, we have determined the margin tax is an income tax and the
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11. INCOME TAXES (Continued)
effect on deferred tax assets and liabilities of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, we recalculated our deferred tax assets and liabilities for Texas based upon the new margin tax and recorded a $1,840,000 deferred tax benefit for the Texas margin tax in 2006.
At June 30, 2008 and 2007, we had net operating loss ("NOL") carryforwards for tax purposes of approximately $17.8 million and $12.8 million. The remaining net operating losses principally expire between 2024 and 2028. $2.2 million of these NOL carryforwards will be unavailable to offset any future taxable income due to limitations from change in ownership as defined in Section 382 of the Internal Revenue Service code. The tax effect of this limitation is recorded as a valuation allowance of $770,000 at both June 30, 2008 and 2007.
12. 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 has been appealed.
Other Cases
On April 28, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1922, Robert and Glenda Adcock, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. ("Adcock"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The
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12. COMMITMENTS AND CONTINGENCIES (Continued)
plaintiffs (i) allege negligence, res ipsa loquitor, trespass and nuisance and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $5,439,958. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) 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.
On July 6, 2006, Anna McMordie Henry and Joni McMordie Middleton intervened in the Adcock case. The intervenors (i) allege negligence and (ii) seek damages totaling $64,357 as well as exemplary damages.
On July 20, 2006, Abraham Brothers, LP, Edward C. Abraham, Salem A. and Ruth Ann Abraham and Jason M. Abraham intervened in the Adcock case. The intervenors (i) allege negligence, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling $3,252,862. In addition, the intervenors seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors 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.
On August 9, 2006, Riley Middleton intervened in the Adcock case. The intervenor (i) alleges negligence and (ii) seeks damages totaling $233,386 as well as exemplary damages.
On April 10, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas, Cause No. 1920, Joseph Craig Hutchison and Judy Hutchison v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc. ("Hutchinson"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and trespass and (ii) seek damages of $621,058, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs seek exemplary damages.
On May 1, 2006, the following lawsuit was filed in the 31st Judicial District Court of Roberts County, Texas: Cause No. 1923, Chisum Family Partnership, Ltd. v. Cano, W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd. and WO Energy, Inc. ("Chisum"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleges negligence and trespass and (ii) seeks damages of $53,738.82, including, but not limited to, damages to their land and certain remedial expenses. In addition, the plaintiffs seek exemplary damages.
On August 9, 2006, the following lawsuit was filed in the 233rd Judicial District Court of Gray County, Texas, Cause No. 34,423, Yolanda Villarreal, Individually and on behalf of the Estate of Gerardo Villareal v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd., and WO Energy, Inc. ("Villarreal"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and (ii) seek damages for past and future financial support in the amount of $586,334, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages, for the wrongful death of Gerardo Villarreal who they claim died as a result of the fire. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable under vicarious liability theories. On August 22,
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12. COMMITMENTS AND CONTINGENCIES (Continued)
2006, relatives of Roberto Chavira intervened in the case alleging similar claims and seeking damages for lost economic support and lost household services in the amount of $894,078, in addition to undisclosed damages for wrongful death and survival damages, as well as exemplary damages regarding the death of Roberto Chavira.
On March 14, 2007, the following lawsuit was filed in 100th Judicial District Court in Carson County, Texas; Cause No. 9994, Southwestern Public Service Company d/b/a Xcel Energy v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc. ("SPS"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiff (i) alleges negligence and breach of contract and (ii) seeks $1,876,000 in damages for loss and damage to transmission and distribution equipment, utility poles, lines and other equipment. In addition, the plaintiff seeks reimbursement of its attorney's fees.
On May 2, 2007, the following lawsuit was filed in the 84th Judicial District Court of Hutchinson County, Texas, Cause No. 37,619, Gary and Genia Burgess, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Burgess"). Eleven plaintiffs claim that electrical wiring and equipment relating to oil and gas operations of the Company or certain of its subsidiaries started a wildfire that began on March 12, 2006 in Carson County, Texas. Five of the plaintiffs are former plaintiffs in the Adcock matter. The plaintiffs (i) allege negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $1,997,217.86. In addition, the plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On May 15, 2007, William L. Arrington, William M. Arrington and Mark and Le'Ann Mitchell intervened in the SPS case. The intervenors (i) allege negligence, res ipsa loquitor, nuisance, and trespass and (ii) seek damages, including, but not limited to, damages to their land, buildings and livestock and certain remedial expenses totaling approximately $118,320. In addition, the intervenors seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The intervenors 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.
On September 25, 2007, the Texas Judicial Panel on Multidistrict Litigation granted Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W. O. Operating Company, Ltd, and WO Energy, Inc.'s Motion to Transfer Related Cases to Pretrial Court pursuant to Texas Rule of Judicial Administration 13. The panel transferred all pending cases (Adcock, Chisum, Hutchison, Villarreal, SPS, and Burgess, identified above, and Valenzuela, Abraham Equine, Pfeffer, and Ayers, identified below) that assert claims against the Company and its subsidiaries related to wildfires beginning on March 12, 2006 to a single pretrial court for consideration of pretrial matters. The panel transferred all then-pending cases to the Honorable Paul Davis, retired judge of the 200th District Court of Travis County, Texas, as Cause No. D-1-GN-07-003353.
On October 3, 2007, Firstbank Southwest, as Trustee for the John and Eddalee Haggard Trust (the "Trust") filed a Petition in intervention as part of the Hutchison case. The Trust claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The Trust (i) alleges
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. COMMITMENTS AND CONTINGENCIES (Continued)
negligence and trespass and (ii) seeks damages of $46,362.50, including, but not limited to, damages to land and certain remedial expenses. In addition, the Trust seeks exemplary damages.
On December 18, 2007, the following lawsuit was filed in the 348th Judicial District Court of Tarrant County, Texas, Cause No. 348-227907-07, Norma Valenzuela, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Valenzuela"). Six plaintiffs, including the two plaintiffs and intervenor from the nonsuited Martinez case, claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County, Texas. The plaintiffs (i) allege negligence and (ii) seek actual damages in the minimal amount of $4,413,707 for the wrongful death of four relatives, Manuel Dominguez, Roberto Chavira, Gerardo Villarreal and Medardo Garcia, who they claim died as a result of the fire. In addition, plaintiffs seek (i) reimbursement for their attorney's fees and (ii) exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On January 10, 2008, Philip L. Fletcher intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $120,408, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On January 15, 2008, the Jones and McMordie Ranch Partnership intervened in the consolidated case in the 200th District Court of Travis County, Texas as part of the SPS case. The intervenor (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $86,250.71, including, but not limited to, damages to his livestock, attorney's fees and exemplary damages. The intervenor also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or as a partnership or de facto partnership.
On February 11, 2008, the following lawsuit was filed in the 48th Judicial District Court of Tarrant County, Texas: Cause No. 048-228763-08, Abraham Equine, Inc. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Abraham Equine"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleges negligence, trespass and nuisance and (ii) seeks damages of $1,608,000, including, but not limited to, damages to its land, livestock and lost profits. In addition, the plaintiff seeks (i) reimbursement for its attorney's fees and (ii) exemplary damages. The plaintiff also claims that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. COMMITMENTS AND CONTINGENCIES (Continued)
On March 10, 2008, the following lawsuit was filed in the 352nd Judicial District Court of Tarrant County, Texas, Cause No. 352-229256-08, Gary Pfeffer v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Pfeffer"). The plaintiff claims that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiff (i) alleges negligence, trespass and nuisance, (ii) seeks undisclosed damages for the wrongful death of his father, Bill W. Pfeffer, who he claims died as a result of the fire and (iii) seeks actual damages of $1,023,572.37 for damages to his parents' home and property. In addition, the plaintiff seeks exemplary damages. The plaintiff also claims that Cano and its subsidiaries are jointly and severally liable as a general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On March 11, 2008, the following lawsuit was filed in the 141st Judicial District Court of Tarrant County, Texas, Cause No. 141-229281-08, Pamela Ayers, et al. v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Ayers"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) allege negligence and (ii) seek undisclosed damages for the wrongful death of their mother, Kathy Ryan, who they claim died as a result of the fire. In addition, the plaintiffs seek exemplary damages. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership. Cano and its subsidiaries filed a Motion to Dismiss or, in the Alternative, to Transfer Venue and a Notice of Tag Along transferring the case to the Multidistrict Litigation Case in the 200th Judicial District Court of Travis County, Texas. On May 2, 2008, the Court heard Cano's Motion to Dismiss or, in the Alternative, to Transfer Venue and took the motion under advisement.
On March 12, 2008, the following lawsuit was filed in the 17th Judicial District Court of Tarrant County, Texas, Cause No. 017-229316-08, The Travelers Lloyds Insurance Company and Travelers Lloyds of Texas Insurance Company v. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating, Ltd. and WO Energy, Inc. ("Travelers"). The plaintiffs claim that the electrical wiring and equipment of Cano or certain of its subsidiaries relating to oil and gas operations started a wildfire that began on March 12, 2006 in Carson County. The plaintiffs (i) allege negligence, res ipsa loquitor, and trespass and (ii) claim they are subrogated to the rights of their insureds for damages to their buildings and building contents totaling $447,764.60. The plaintiffs also claim that Cano and its subsidiaries are jointly and severally liable as a single business enterprise and/or general partnership or de facto partnership.
On August 15, 2008, the trial court denied motions for summary judgment filed by Cano in the Adcock, Chisum, Hutchinson, Villarreal, SPS, Burgess, and Valenzuela cases. The SPS case is set for jury trial on February 16, 2009. None of the other above-mentioned cases are currently set for trial; however, the Company anticipates that the trial court will set these matters for jury trials.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. COMMITMENTS AND CONTINGENCIES (Continued)
Due to the inherent risk of litigation, the ultimate outcome of these cases and any jury trial is uncertain and unpredictable; however, at this time Cano management believes the suits are without merit and is vigorously defending itself and its subsidiaries.
Insurance Settlement Related to the Fire Litigation
On June 20, 2006, the following lawsuit was filed in the United States District Court for the Northern District of Texas, Fort Worth Division, C.A. No. 4-06cv-434-A, Mid-Continent Casualty Company, Plaintiff, vs. Cano Petroleum, Inc., W.O. Energy of Nevada, Inc., W.O. Operating Company, Ltd. and W.O. Energy, Inc. seeking a declaration that the plaintiff is not responsible for pre-tender defense costs and that the plaintiff has the sole and exclusive right to select defense counsel and to defend, investigate, negotiate and settle the litigation described above. On September 18, 2006, the First Amended Complaint for Declaratory Judgment was filed with regard to the cases described above. Cano and its subsidiaries were served with the lawsuit between September 26-28, 2006.
On February 9, 2007, Cano and its subsidiaries entered into a Settlement Agreement and Release with the plaintiff pursuant to which in exchange for mutual releases, in addition to the approximately $923,000 that we have been reimbursed by plaintiff, the plaintiff agreed to pay to Cano within 20 business days of February 9, 2007 the amount of $6,699,827 comprised of the following: (a) the $1,000,000 policy limits of the primary policy; (b) the $5,000,000 policy limits of the excess policy; (c) $500,000 for future defense costs; (d) $144,000 as partial payment for certain unpaid invoices for litigation related expenses; (e) all approved reasonable and necessary litigation related expenses through December 21, 2006 that are not part of the above-referenced $144,000; and (f) certain specified attorneys fees. During February 2007, we received the $6,699,827 payment from Mid-Con. Of this $6,699,827 amount, the payments for policy limits amounting to $6,000,000, in accordance with the senior credit agreement (Note 4), were placed in a controlled bank account and the use of the proceeds was specified to pay attorneys' fees, settlement amounts and other litigation expenses incurred to defend and/or settle the fire litigation, and for general corporate purposes. Specifically, we could not use the proceeds to fund capital expenditures. Accordingly, our consolidated balance sheets reflect the $6,000,000 as a liability under deferred litigation credit. As of June 30, 2008, we had fully expended the restricted cash and we no longer had a balance for restricted cash.
Other
Occasionally, we are involved in other various lawsuits and certain governmental proceedings arising in the ordinary course of business. Our management does not believe that the ultimate resolution of any current matters that are not set forth above, 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 our business or has a material interest adverse to our business.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. COMMITMENTS AND CONTINGENCIES (Continued)
Environmental
To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Leases
During June 2006, we entered into a non-cancelable operating lease for our principal executive offices in Fort Worth. The lease expires on May 31, 2011. Our remaining obligation for the life of the lease is $1.2 million. In addition, during October 2005 we entered into a five year operating lease for our field offices at W.O. Energy of Nevada, Inc. The lease expires on October 1, 2010. Future minimum rentals due under our non-cancellable operating leases were as follows on June 30, 2008:
Rent expense amounted to $379,000, $340,000, and $98,000, for the years ended June 30, 2008, 2007, and 2006, 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:
13. SUBSEQUENT EVENT
On September 5, 2008, we entered into an agreement to sell our 100% membership interest in Pantwist, LLC for $42.7 million cash, subject to closing adjustments. The sale has an effective date of July 1, 2008, and we expect to finalize the sale on or before October 1, 2008. The primary asset of the Pantwist, LLC is the Pantwist Properties. After paying down outstanding debt and the possible payment of a portion of the Series D Preferred Stock, we expect to commit any remaining net proceeds from the sale of the Pantwist Properties, when finalized, to continued development of the Panhandle and Cato Properties and/or to strategic acquisitions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
All of our operations are directly related to oil and natural gas producing activities located in Texas, Oklahoma and New Mexico.
Capitalized Costs Relating to Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Producing Activities
Proved Reserves
Our proved oil and natural gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Continued)
The term proved reserves is defined by the Securities and Exchange Commission in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933, as amended. In general, proved reserves are the estimated quantities of oil, gas and liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserves are summarized in the table below.
The base prices used to compute the crude oil and natural gas reserves represent the NYMEX oil and natural gas prices at June 30, 2008, 2007 and 2006, respectively. For the reserves at June 30, 2008, the crude oil and natural gas prices were $140.00 per barrel and $13.15 per MMbtu, respectively. For
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Continued)
the reserves at June 30, 2007, the crude oil and natural gas prices were $70.47 per barrel and $6.40 per MMbtu, respectively. For the reserves at June 30, 2006, the crude oil and natural gas prices were $73.94 per barrel and $5.83 per MMbtu, respectively.
For the reserves at June 30, 2008, 2007 and 2006, the purchases of minerals in place pertain to our acquisitions of oil and natural gas properties located in the Texas Panhandle and New Mexico.
For the reserves at June 30, 2006, the above table identifies a 16,421 Mcf reduction in natural gas reserves for revisions of prior estimates. Approximately 7,200 Mcf pertains to renegotiation of a natural gas purchase contract that was not finalized at June 30, 2006; therefore, these reserves were excluded at June 30, 2006, but were included in the reserve at June 30, 2007 since the natural gas purchase contract was finalized by that date. The remaining 9,225 Mcf reduction is primarily due to the reassessment of natural gas production from the planned waterflood implementation in the Panhandle Field.
For the reserves at June 30, 2007, the extensions and discoveries pertain to our drilling and completing wells in the Barnett Shale formation at our Desdemona Properties.
For the reserves at June 30, 2008, the reductions in crude oil and natural gas reserves for revisions of prior estimates primarily pertain to our Desdemona and Pantwist Properties. For the Desdemona-Barnett Shale, we considered the lower performance from the existing wells and current industry practice that limited the number of PUD locations that could be booked against existing wells. Therefore, PUD reserves were reduced by approximately 3 MMBOE due to lower performance results from the existing wells and further reduced by another 5 MMBOE as the number of PUD drilling locations decreased from 76 to 40. In addition, we had a material amount of reclassifications from PUD to probable reserves associated with the Pantwist Properties as we could not commit to developing PUD reserves within five years, based on current industry practice, since this is an asset for which we are currently seeking strategic alternatives.
Standardized Measure
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Continued)
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:
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, 2008, 2007, and 2006 is as follows:
Changes in Standardized Measure of Discounted Future Cash Flows:
The primary changes in the standardized measure of discounted estimated future net cash flows for the years ended June 30, 2008, 2007, and 2006 are as follows: