Item 1. Business.
GENERAL
Cubic Energy, Inc. (referred to as “Cubic”, “we”, “our”, “us” or the “Company”) is an independent energy company engaged in the development and production of, and exploration for, crude oil, natural gas and natural gas liquids. Our oil and gas assets are concentrated principally in Texas and Louisiana. At June 30, 2009, our total proved reserves were 21,076,880 Mcfe.
Our predecessor was incorporated in October 1978. Cubic was incorporated in 1999 in the State of Texas. Our principal executive office is located at 9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972) 686-0369.
HISTORY
In December 1997, we entered into a Stock Purchase Agreement (the “Agreement”) pursuant to which the Company issued 12,500,000 shares of our common stock in exchange for the conveyance to the Company of certain oil and gas properties by Calvin A. Wallen, III and his affiliates. In connection with the Agreement, three of the five members of the Board of Directors resigned and new directors were appointed, including Mr. Wallen, who also became President and CEO of the Company.
Prior to the Agreement, we focused primarily on the acquisition of non-operated working interests and overriding royalty interests in oil and gas properties. Subsequent to the Agreement in December 1997, we moved our headquarters from Tulsa, Oklahoma to Garland, Texas in order to utilize an affiliate’s assembled team of experienced management whose substantial expertise lay in acquisition, exploitation and development and the ability to manage both operated and non-operated oil and gas properties. Current management believes that the ability to operate the vast majority of our own properties, through this affiliate, will result in significant cost savings to the Company. In addition, after reviewing our existing property portfolio and refining our new business strategy, the management team initiated a divestment strategy to dispose of our non-strategic assets in non-core areas in order to concentrate on building core reserves. Pursuant to this strategy, we have acquired additional properties in our core areas, primarily in Louisiana, as well as establishing a drilling program for the drilling of exploratory, development and infill wells, a strategy previously unavailable to us due to the technical expertise and experience required and the lack of available resources. We have made substantial progress in redirecting our strategic business efforts and believe that attractive opportunities remain for development of our remaining assets and acquisition of future assets.
On February 6, 2006, the Company entered into a Purchase Agreement with Tauren Exploration, Inc. (“Tauren”), an entity wholly owned by Calvin A. Wallen III, the Company’s Chairman of the Board and Chief Executive Officer, with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right to acquire at “cost” (as defined in the Purchase Agreement) a working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 unregistered shares of Company common stock, (c) an unsecured 12.5% short-term promissory note in the amount of $1,300,000, which note is convertible into Company common stock at a conversion price of $0.80 per share (the “Tauren Note”), and (d) a drilling credit of $2,100,000.
On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital (“Wells Fargo”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). In connection with entering into the Credit Facility, the Company issued to Wells Fargo warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company common stock at an original exercise price of $1.00 per share. The term loan was initially convertible into 5,000,000 shares of Cubic common stock at an original conversion price of $1.00 per share. The Revolving Note is subject to a borrowing base (the “Borrowing Base”), initially set at $4,000,000, and is subject to periodic review. On July 27, 2007, Wells Fargo increased the Borrowing Base to $6,600,000 in order to fund the drilling and casing costs of two new wells in the Company’s Johnson Branch acreage in Caddo Parish, Louisiana. On September 7, 2007, Wells Fargo increased the Borrowing Base to $8,600,000 in order to fund the remaining drilling and casing costs of five wells drilled since the beginning of fiscal 2008, the drilling and casing costs of two new wells, and the costs of installing a gathering/sales line and associated equipment in the Company’s Johnson Branch acreage. On November 19, 2007, Wells Fargo increased the Borrowing Base to $14,500,000 in order to fund the completion costs and casing of eight wells already successfully drilled and the drilling of four additional wells located in the Company’s Johnson Branch acreage. On May 8, 2008, Wells Fargo increased the Borrowing Base to $20,000,000 in order to fund the completion costs and casing of the four recently-drilled wells located in the Company’s Johnson Branch acreage (including two vertical wells drilled into the Bossier/Haynesville shales) and the drilling of two additional wells located in the Company’s Bethany Longstreet acreage in Caddo and DeSoto Parishes. On June 26, 2009, Wells Fargo decreased the Company’s borrowing base to $7,500,000. This redetermination required the Company to make a payment of $12,500,000 by September 1, 2009. Wells Fargo has issued the Company extensions to November 1, 2009. The Company has the option of making this payment in five equal installments.
The terms of the Credit Facility, among other things, prohibit the Company from merging with another company or paying dividends, and limit additional indebtedness, sales of certain assets and investments. Upon the repayment in full of the Credit Facility, and with respect to certain properties, upon the occurrence of the conditions set forth in Section 2.14 of the Credit Agreement, the Company agreed to convey a net profits interest to Wells Fargo in an amount equal to 5% of Cubic’s net interest in certain of its Louisiana properties.
On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 (the “Subordinated Note”) to Diversified Dynamics Corporation (the “Lender”), an entity controlled by William Bruggeman who beneficially owns more than 5% of the common stock of the Company, and who subsequently became a director of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. As consideration for the loan made by the Lender pursuant to the Subordinated Note, the Company agreed to convey to the Lender, upon the repayment in full of the indebtedness evidenced by the Subordinated Note and the repayment in full of the senior indebtedness evidenced by the Credit Facility with Wells Fargo, an undivided 0.375% net profits interest in the future production of hydrocarbons from or attributable to Cubic’s net interest in its Louisiana properties. The proceeds of the Subordinated Note were used for general corporate and working capital purposes.
On May 8, 2008, the Credit Facility with Wells Fargo was amended by the First Amendment to the Credit Agreement (the “First Amendment”). Material provisions of the First Amendment included the following: (i) the Company may not prepay all or any part of the principal balance outstanding on the Term Loan prior to its maturity on March 1, 2010; and (ii) the amount of the Borrowing Base was increased to $20,000,000, which amount was fully drawn upon, on August 20, 2008.
STRATEGY
Our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to higher risk, high reserve potential prospects. Our focus is primarily on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate some externally generated prospects and plan to participate in some of these opportunities to enhance our portfolio.
We are currently focusing our domestic exploration activities to develop our undeveloped leasehold opportunities in Louisiana and Texas. Currently we have exploration opportunities and seek to acquire additional leasehold interests in Caddo and DeSoto Parishes in Louisiana, and in Palo Pinto, Callahan and Eastland Counties in Texas. These areas are a part of geologic studies utilizing regional trend surface analysis, 2-D and 3-D seismic data, AVO analysis and/or vast sub-surface control. Prospects have been developed from approximately 4,000 to 12,000 feet in depth in the: Bossier/Haynesville shales; Cotton Valley, Hosston, Gloyd, Pettet, Paluxy, and Strawn sandstones; Bend conglomerate; and Caddo limestone.
PRINCIPAL OIL AND GAS PROPERTIES
The following table summarizes certain information with respect to our principal areas of operation at June 30, 2009:
Our Texas properties are situated in Palo Pinto, Eastland and Callahan Counties. Our Louisiana properties are situated in Caddo Parish and in DeSoto Parish. At June 30, 2009, the Louisiana properties contained the vast majority of our proved reserves, a situation that is expected to continue. The Texas properties consist primarily of wells acquired by the Company in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. The vast majority of the Louisiana properties were acquired on or about October 1, 2004, January 11, 2005 and February 6, 2006.
Our net production for the fiscal year ended June 30, 2009 for all of the Company’s wells averaged approximately 766 Mcf of natural gas per day, 5 barrels of oil per day and 213 gallons of natural gas liquids per day as compared to approximately 624 Mcf of natural gas per day, 5 barrels of oil per day and 122 gallons of natural gas liquids per day in the fiscal year ended June 30, 2008.
RECENT DEVELOPMENTS
On Friday, June 26, 2009, the Company received a letter from NYSE Amex, LLC (the “Exchange”) stating that the Exchange believes that the Company is not in compliance with Section 1003(a)(iv) of the Exchange’s Company Guide as the Company has sustained losses or its financial condition has become impaired to the extent that it appears questionable, in the opinion of the Exchange, as to whether the Company will be able to continue operations and/or meets its obligations as they mature. On Monday, July 27, 2009, the Company submitted its compliance plan to the Exchange detailing how the Company intends to regain compliance. On September 15, 2009, the Exchange notified the Company that the Exchange has accepted the compliance plan, and granted the Company an extension until December 28, 2009 to evidence its compliance with the Exchange’s continued listing standards.
On Monday, June 29, 2009, the Company announced it received a letter from Wells Fargo informing the Company that Wells Fargo has made a redetermination of the Borrowing Base, which reduced the Borrowing Base from $20.0 million to $7.5 million, requiring a payment of $12.5 million from the Company to Wells Fargo. Through waivers, Wells Fargo extended the due date for the payment until November 1, 2009, and the Company has the right to pay the deficiency in five monthly installments as provided in the Credit Facility.
The Company is focused on capital restructuring and regaining full compliance on the Exchange. Capital restructuring is intended to support capital expenditures for non-operated working interests, to fund horizontal drilling, to fracture stimulate additional zones of certain Johnson Branch wells and to test the Bossier shale. The capital restructuring is an integral part of the Company’s’ strategic plan to regain full compliance on the Exchange.
GAS GATHERING
Cubic has developed its infrastructure in Johnson Branch with approximately 16 miles of gathering lines and pipeline constructed for its currently producing wells and any further completions. In addition, a Johnson Branch tap, common point and compression facility were completed in November 2007 and are currently operational. The Company has also developed its infrastructure with approximately 7.8 miles of gathering lines and owns two taps in its Bethany Longstreet acreage.
MARKETING OF PRODUCTION
Crude Oil and Natural Gas
Our production consists mainly of natural gas. We market our operated production of natural gas to three purchasers (i) in Texas, Enbridge G & P, LP, and (ii) in Louisiana, EROC Gathering Company, LP and NGTS, LP. We sell our crude oil and condensate production at or near the well-site; although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline and is typically committed to arrangements having a term of one year or less. We have not engaged in crude oil hedging or trading activities. We utilize short-term gas contracts with prices that are related to market conditions in varying degrees and have not engaged in natural gas hedging or futures trading.
We believe we would be able to locate alternate purchasers in the event of the loss of any one of these purchasers, and that any such loss would not have a material adverse effect on our financial condition or results of operations. Revenue from the sale of natural gas totaled $1,671,503 for fiscal 2009 and represented 90% of our total oil and gas revenues for that fiscal year.
Price Considerations
Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil (“NYMEX-WTI”). The average crude oil price per barrel received by us in fiscal 2009 was $60.00 as compared to $102.17 in fiscal 2008. Natural gas and natural gas liquids prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMbtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our natural gas. Average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2009 was $5.98 as compared to $9.01 in fiscal 2008. The average natural gas liquids price per gallon received by us in fiscal 2009 was $1.12 compared to $1.66 in fiscal 2008.
OIL AND GAS RESERVES
The following tables set forth the proved developed and proved undeveloped reserves at June 30, 2009, the estimated future net cash flows from such proved reserves and the Standardized Measure of Discounted Future Net Cash Flows attributable to our reserves at June 30, 2009, 2008 and 2007:
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net cash flows from the production of proved reserves, after giving effect to income taxes. See “Note J - Oil and gas reserves information (unaudited)” in the Notes to the Financial Statements of the Company included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Statement of Financial Accounting Standards (“FAS”) No. 69 (“FAS No. 69”), “Disclosures about Oil and Gas Producing Activities.”
The information set forth in this Annual Report relating to our proved reserves, estimated future net cash flows and present values is taken from reports prepared by the Dallas office of RPS Scotia, Inc., an independent, petroleum engineering firm, for fiscal years 2009, 2008 and 2007. The estimates of this independent petroleum engineering firm were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. Information with respect to approximately 2% of the total proved reserves as of June 30, 2009, was prepared in-house and was not reviewed by an independent engineering firm. No reports on our reserves have been filed with any federal agency. In accordance with guidelines of the SEC, our estimates of proved reserves and the future net revenues from which present values are derived are made using year end oil and gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net cash flows, but such costs do not include debt service or general and administrative expenses.
There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. The reserve data set forth in this Annual Report represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of our oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves.
Costs Incurred
The following table shows certain information regarding the costs incurred by us in our property acquisition, development and exploratory activities during the periods indicated.
Drilling Results
We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling commenced. We did not acquire any wells during these periods. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated by those wells.
NET PRODUCTION, SALES PRICES AND COSTS
The following table presents certain information with respect to production, prices and costs attributable to all oil and gas property interests owned by us for the fiscal years ended June 30, 2009, 2008 and 2007:
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth our domestic productive wells at June 30, 2009:
Acreage
The following table sets forth our undeveloped and developed gross and net leasehold acreage at June 30, 2009. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.
OPERATIONS
Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator’s direct expenses and monthly per well supervision fees. Per well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. We are not the operator of our wells, but, in all cases, except for three wells in Northwest Louisiana in which we have minor working interests, and which are operated by Chesapeake Energy Corp., Fossil Operating, Inc. (“Fossil”), an entity wholly owned by Mr. Wallen, is the operator. Fossil charges the Company, without mark-up, for the Company’s working interest portion of the direct operating costs and overhead costs (which are comprised of administrative, supervision, office services and warehousing costs) that Fossil incurs with respect to our wells.
We have contract relationships with petroleum engineers, geologists and other operations and production specialists who we believe will be able to improve production rates, increase reserves and/or lower the cost of operating our oil and gas properties.
EMPLOYEES
At September 4, 2009, the Company had nine (9) employees, four (4) full-time and five (5) part-time. We regularly use independent consultants and contractors to perform various professional services, including well-site supervision, design, construction, permitting and environmental assessment. We use independent contractors to perform field and on-site production operation services.
FACILITIES
The Company’s principal executive and administrative offices are located at 9870 Plano Road, Dallas, Texas. The offices are subleased on a month-to-month basis from an affiliate controlled by Mr. Wallen and the offices are owned by this affiliate. The average monthly amount charged to the Company during the year ended June 30, 2009, was $2,229. The Company believes that there is other appropriate space available in the event the Company should terminate its current leasing arrangement.
COMPETITION
We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.
Recent increased oil and natural gas drilling activity in east Texas and northwest Louisiana has resulted in increased demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to experienced temporary or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling and completing. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.
Regulation
Exploration and Production. The exploration, production and sale of oil and natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. All of these regulations may adversely affect the rate at which wells produce oil and natural gas and the number of wells we may drill. All statements in this report about the number of locations or wells reflect current laws and regulations.
Laws and regulations relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.
Environmental Matters. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities or oil and natural gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.
A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and natural gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid waste, which are subject to classification as hazardous substances under CERCLA.
The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.
There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandoning of oil and natural gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.
We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and natural gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that
environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.
In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.
Marketing and Transportation. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”) that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances.
The ultimate impact of the complex rules and regulations issued by FERC since 1985 cannot be predicted. We cannot predict what further action FERC will take on these matters. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.
Additional proposals and proceedings that might affect the natural gas industry are frequently made before Congress, FERC and the courts. The natural gas industry historically has been very heavily regulated, and there have been indications that future regulatory efforts might become more vigorous, possibly resulting in more stringent regulation.
Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and gas industry, many of which are used in this Report.
“Bbl” means a barrel of 42 U.S. gallons, used herein in reference to oil or other liquid hydrocarbons.
“Bcf” means billion cubic feet.
“Bcfe” means Bcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
“Btu” means British thermal unit, which means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
“Casing” means a type of pipe that is used for encasing a smaller diameter carrier pipe for installation in a well. Casing is used to send off fluids from the hole or keep a hole from caving in.
“Completion” means the installation of permanent equipment for the production of oil or gas.
“Compressor Station” means a facility in which the pressure of natural gas is raised to facilitate its transmission through pipelines.
“Condensate” means hydrocarbons naturally occurring in the gaseous phase in a reservoir that condense to become a liquid at the surface due to the change in pressure and temperature.
“Cubic Foot” means the volume of gas that fills one cubic foot of space under standard temperature and pressure conditions. Standard pressure is 14.73 psi and standard temperature is 60 degrees Fahrenheit.
“Developed Acreage” means the number of acres that are allocated or assignable to producing wells or wells capable of production.
“Development Drilling” or “Development Well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry Hole” or “Dry Well” means a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil and gas well.
“Estimated Future Net Cash Flows” means estimated future gross cash flows to be generated from the production of proved reserves, net of estimated production, future development costs, and future abandonment costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to deprecation, depletion and amortization.
“Exploration” is the act of searching for potential sub-surface reservoirs of gas or oil. Methods include the use of magnetometers, gravity meters, seismic exploration, surface mapping, and the drilling of exploratory test wells (known as “wildcats”).
“Exploratory Drilling” or “Exploratory Well” means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
“Farm-In” or “Farm-Out” means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” and the assignor issues a “farm-out.”
“Finding and Development Costs” The total costs incurred for exploration and development activities (excluding exploratory drilling in progress and drilling inventories), divided by total proved reserve additions. To the extent any portion of the proved reserve additions consist of proved undeveloped reserves; additional costs would have to be incurred in order for such proved undeveloped reserves to be produced. This measure may differ from the measure used by other oil and natural gas companies.
“Gas” means natural gas.
“Gathering System” means a system of pipelines, compressor stations and any other related facilities that gathers natural gas from a supply region and transports it to the major transmission systems.
“Gross” when used with respect to acres or wells, means the total acres or wells in which we have a working interest.
“Horizontal Drilling” means drilling a well that deviates from the vertical and travels horizontally through a prospective reservoir.
“Hydrocarbons” means an organic chemical compound of hydrogen and carbon. Hydrocarbons are a large class of liquid, solid or gaseous organic compounds, which are the basis of almost all petroleum products.
“Lease” means a formal agreement between two or more parties where the owner of the land grants another party the right to drill and produce hydrocarbons in exchange for payment.
“Mcf” means thousand cubic feet.
“Mcfe” means Mcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
“MMbtu” means one million Btus.
“MMcf” means one million cubic feet.
“MMcfe” means MMcf of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
“Natural Gas Liquids” means liquid hydrocarbons which have been extracted from natural gas (e.g., ethane, propane, butane and natural gasoline).
“Net” when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.
“Net Production” means production that is owned by the Company less royalties and production due others.
“NYMEX” New York Mercantile Exchange
“Operator” means the individual or company responsible for the exploration, development and production of an oil or gas well or lease.
“Pipeline” means all parts of a physical facility through which gas is transported, including pipe, valves and other appendages attached to the pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
“Present Value”, “PV-10” or “Standard Measure” when used with respect to oil and gas reserves, is the pre-tax present value, discounted at an annual rate of 10%, of the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation (except to the extent a contract specifically provides otherwise), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.
“Productive Wells” or “Producing Wells” consist of producing wells and wells capable of production, including natural gas wells waiting on pipeline connections.
“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved Reserves” means the estimated quantities of crude oil, natural gas and natural gas liquids which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if either actual production or conclusive formation tests support economic producibility. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (b) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such resources.
“Proved Undeveloped Reserves” means reserves that are recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
“Reserves” means proved reserves.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
“Sandstone” means rock composed mainly of sand-sized particles or fragments of the mineral quartz, which, because these grains are rigid, will withstand tremendous pressures without being compacted.
“Shale” means a type of rock composed of common clay or mud. When clay is compacted under great pressure and temperature deep in the earth, water contained in the clay is expelled, and clay turns into shale.
“2-D Seismic” means an advanced technology method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.
“3-D Seismic” means an advanced technology method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
“Undeveloped Acreage” means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
“Working Interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.
AVAILABILITY OF INFORMATION
We file periodic reports and proxy statements with the Securities and Exchange Commission (the “SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding Cubic Energy, Inc. and other companies that file electronically with the SEC.
Our website address is www.cubicenergyinc.com. We make available on our website free of charge copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably possible after we electronically file or furnish such material with the SEC.
Item 1A.
Item 1A. Risk Factors.
You should carefully consider the following risk factors, in addition to the other information set forth in this Report, before investing in shares of our common stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. Some information in this Report may contain “forward-looking” statements that discuss future expectations of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual results to differ materially from those contained in any forward-looking statements.
Servicing our debt requires a significant amount of cash, and we will not have sufficient cash flow from our business to pay our substantial debt as it comes due.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our ability to obtain additional debt and /or equity financing, which is subject to economic and financial factors beyond our control. Our business will not generate cash flow from operations sufficient to pay our obligations to Wells Fargo. We may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition in the immediate future, as well as the value of our properties. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on the market price of our equity securities.
On June 26, 2009 Well Fargo re-determined the Borrowing Base, which reduced the credit limit on the Revolving Note from $20,000,000 to $7,500,000, requiring a payment of $12,500,000 from the Company to Wells Fargo. The Company has the right to pay the deficiency in five monthly installments.
Subsequent to the redetermination, the Company has received extensions of time until November 1, 2009 from Wells Fargo to comply with the terms of that letter from Wells Fargo dated June 26, 2009. That June 26, 2009 letter previously informed the Company that the Lender made a borrowing base redetermination and waived any failure of the Company to comply with its obligations under the Credit Agreement as a result of such redetermination until September 1, 2009. There can be no assurance that Wells Fargo will grant any additional extensions.
We may not be able to secure additional funds to make the required payments to Wells Fargo. If we are not successful, Wells Fargo may pursue all remedies available to it under the terms of the Credit Facility including but not limited to foreclosure on our assets. If that were to occur, our shareholders might lose their entire investment.
We will need additional funding in order to make required payments to Wells Fargo, as well as to fund our drilling program.
Our business is highly capital-intensive requiring continuous development and acquisition of oil and gas reserves. In addition, capital is required to operate and expand our oil and gas field operations, to purchase equipment and to fund our drilling program.
At June 30, 2009, we had working capital of $(27,822,536). On March 5, 2007, Cubic entered into the Credit Facility with Wells Fargo providing for the $20,000,000 Revolving Note and the Term Loan of $5,000,000 in order to fund the drilling of new wells. The Company has borrowed the full amount under the Credit Facility. In addition, we are required to make payments to Wells Fargo in an aggregate amount of $12,500,000 as a result of the redetermination of our Borrowing Base. Therefore, the Company’s capital
requirements must be satisfied through additional borrowings under new or renegotiated credit arrangements, the issuance of equity securities or other potential transactions. There can be no assurance that any of these sources of capital will be available or sufficient to satisfy the Company’s capital requirements.
We have experienced and will continue to experience significant capital expenditures and working capital requirements, in order to fund our drilling program. In addition to amounts necessary to satisfy our obligations to Wells Fargo, we expect that we will require additional financing, in addition to cash generated from operations, to fund our expected growth. There can be no assurance, however, that additional financing will be available on acceptable terms or at all. In the event that additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Additionally, failure to drill on certain of our leasehold interests could result in the forfeiture of our interest.
Any future issuances of equity securities would likely result in dilution to our then existing shareholders while incurring additional indebtedness would result in increased interest expense and debt service charges
We face significant competition, and many of our competitors have resources in excess of our available resources.
The oil and gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and sale of crude oil, natural gas and natural gas liquids. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.
Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.
Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We
participate in insurance coverage maintained by the operator of our wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.
We have a history of operating losses and may not be profitable in the future.
We incurred losses of $(24,762,516) and $(5,128,453) for the fiscal years ended June 30, 2009 and 2008, respectively. Our accumulated deficit as of June 30, 2009 was $(49,213,661). Historically, we have funded our operating losses, acquisitions and drilling costs primarily through a combination of private offerings of convertible debt, senior secured debt, and equity securities. However, we have no borrowing availability under the Credit Facility, and we are required to make substantial payments to Wells Fargo as a result of the redetermination of the Borrowing Base. Our success in obtaining the necessary capital resources to fund those payments to Wells Fargo and future costs associated with our operations and drilling plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery of our proved producing and proved developed non-producing oil and gas reserves; (ii) maintain effective cost controls at the corporate administrative office and in field operations; and (iii) obtain additional financing, including through the exercise of outstanding warrants. However, even if we achieve some success with our plans, there can be no assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or to fund our drilling plans.
We have substantial capital requirements necessary for undeveloped properties for which we may not be able to obtain adequate financing.
The majority of our oil and gas reserves are undeveloped. At June 30, 2009, we had proved undeveloped reserves of 20,721,079 Mcfe, which represent approximately 98% of our total proved reserves of 21,076,880 Mcfe. Recovery of the Company’s future undeveloped reserves will require significant capital expenditures to further develop these reserves during fiscal year 2010 and for the foreseeable future. No assurance can be given that our financing sources, following utilization of any available financing sources to satisfy our obligations to Wells Fargo, will be sufficient to fully fund our planned development activities or that development activities will be either successful or in accordance with our schedule. Additionally, any failure to see increases in oil and gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or gas in commercially profitable quantities.
Development of our properties will require additional capital resources. At this time we have significant payment obligations to Wells Fargo, but we have no commitments to obtain any additional debt or equity financing and there can be no assurance that additional financing will be available, when required, on favorable terms or at all. The inability to obtain additional financing will have a material adverse effect on us, including requiring us to cease our oil and gas development plans or farm-out development of our properties, in addition to the impact that the exercise by Wells Fargo of its remedies might have. Any additional financing may involve substantial dilution to the interests of our shareholders at that time.
Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results.
Our revenues, profitability and the carrying value of our oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and gas and the costs of acquiring, finding, developing and producing reserves. Our ability to obtain borrowing capacity, to repay future indebtedness, and to obtain additional capital on favorable terms is also substantially dependent upon oil and gas prices. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and gas; (ii) market uncertainty; and (iii) a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions, the price and availability
of domestic and imported oil and gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore, the marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Volatility in oil and gas prices could affect our ability to market our production through such systems, pipelines or facilities. Substantially all of our natural gas production is currently sold to two gas marketing firms on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during fiscal years 2009, 2008 and 2007, and experienced fluctuations similar to those seen in natural gas prices for those years. Natural gas prices no longer appears to be coupled with oil, while oil prices still fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries (“OPEC”), changes in demand from many Asian countries and other emerging economies, current events in the Middle East, security threats to the United States, and other factors associated with the world political and economic environment. Currently, low natural gas prices are directly due to the over supply of natural gas and the reduction of industrial gas consumption as a result of current economic conditions. We are unable to predict what changes will occur in crude oil, natural gas and natural gas liquids prices.
We are subject to uncertainties in reserve estimates and future net cash flows.
This report contains estimates of our oil and gas reserves and the expected future net cash flows from those reserves, which have been prepared by certain independent petroleum consultants. There are numerous uncertainties inherent in estimating quantities of reserves of oil and gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this report are based on various assumptions, including, for example, constant oil and gas prices, operating expenses, capital expenditures and the availability of funds, and, therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this report. Additionally, our reserves may be subject to downward or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and gas prices and other factors, many of which are beyond our control.
The present value of future net reserves discounted at 10% (the “PV-10”) of proved reserves referred to in this report should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, our reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors. See “Item 1.Business - Oil and Gas Reserves.”
We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.
Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are reasonable, we are not fully insured against all risks. We do not carry business
interruption insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.
From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the duration of such curtailments. We are not currently experiencing any material curtailment of our production.
We intend to continue our development and exploration activities. Exploratory drilling and, to a lesser extent, development drilling of oil and gas reserves involve a high degree of risk that no commercial production will be obtained and/or that production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of Calvin A. Wallen, III, our President, Chairman of the Board, and Chief Executive Officer. The loss of the services of Mr. Wallen would have a material adverse effect on our operations. We have not obtained key personnel life insurance on Mr. Wallen.
Certain of our affiliates control a majority of our outstanding common stock, which may affect other shareholders’ ability to influence matters submitted to a vote of shareholders.
As of September 4, 2009, our executive officers, directors and their affiliates and certain 5% shareholders hold approximately 70% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such shareholders have the ability to exert significant influence or control over our business affairs, including the ability to control the election of directors and results of voting on all matters requiring shareholder approval. This concentration of voting power may delay or prevent a potential change in control.
Certain of our affiliates have engaged in business transactions with the Company, which may result in conflicts of interest.
Certain officers, directors and related parties, including entities controlled by Mr. Wallen, the President, Chairman of the Board and Chief Executive Officer, have engaged in business transactions with the Company which were not the result of arm’s length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.
The liquidity, market price and volume of our stock are volatile, and our stock is subject to certain penny stock rules.
Our common stock is traded on the American Stock Exchange (the “AMEX”). The liquidity of our common stock may be adversely affected, and purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade in that or another suitable trading market.
There is presently only a limited public market for our common stock, and there is no assurance that a ready public market for our securities will develop. It is likely that any market that develops for our common stock will be highly volatile and that the trading volume in such market will be limited. As of September 4, 2009, the trading price of our common stock was below $5.00 per share. The trading price of our common stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results and other events or factors. In addition, the U.S. stock market has from time to time experienced extreme price and volume fluctuations that have affected the market price for many companies and which often have been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities.
We may experience adverse consequences because of required indemnification of officers and directors.
Provisions of our Articles of Incorporation and Bylaws provide that we will indemnify any director and officer as to liabilities incurred in their capacity as a director or officer and on those terms and conditions set forth therein to the fullest extent of Texas law. Further, we may purchase and maintain insurance on behalf of any such persons whether or not we would have the power to indemnify such person against the liability insured against. The foregoing could result in substantial expenditures by us and prevent any recovery from our officers, directors, agents and employees for losses incurred by us as a result of their actions.
Certain anti-takeover provisions may discourage a change in control.
Provisions of Texas law and our Articles of Incorporation and Bylaws may have the effect of delaying or preventing a change in control or acquisition of the Company. Our Articles of Incorporation and Bylaws include provisions for a classified Board of Directors (although we do not currently have a classified board), “blank check” preferred stock (the terms of which may be fixed by our Board of Directors without shareholder approval), purported limits on shareholder action by written consent in lieu of a meeting, and certain procedural requirements governing shareholder meetings. These provisions could have the effect of delaying or preventing a change in control of the Company.
We do not intend to declare dividends in the foreseeable future.
Our Board of Directors presently intends to retain all of our earnings for the repayment of debt and the expansion of our business. We therefore do not anticipate the distribution of cash dividends in the foreseeable future. Any future decision of our Board of Directors to pay cash dividends will depend, among other factors, upon our earnings, financial position and cash requirements.
Our internal controls over financial reporting may not be effective, which could have a significant and adverse effect on our business.
Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the Securities and Exchange Commission, which we collectively refer to as Section 404, require us to evaluate our internal controls over financial reporting to allow management to report on those internal controls as of the end of each year. Section 404 will also require our independent registered public accounting firm to attest to the effectiveness of our internal controls over financial reporting in future periods. Effective internal controls are necessary for us to produce reliable financial reports and are important in our effort to prevent financial fraud. In the course of our Section 404 evaluations, we may identify conditions that may result in significant deficiencies or material weaknesses and we may conclude that enhancements, modifications or changes to our internal controls are necessary or desirable. Implementing any such matters would divert the attention of our management, could involve significant costs, and may negatively impact our results of operations.
We note that there are inherent limitations on the effectiveness of internal controls, as they cannot prevent collusion, management override or failure of human judgment. If we fail to maintain an effective system of internal controls or if management or our independent registered public accounting firm were to discover
material weaknesses in our internal controls, we may be unable to produce reliable financial reports or prevent fraud, and it could harm our financial condition and results of operations, result in a loss of investor confidence and negatively impact our share price.
We may not have satisfactory title to our properties.
Our contract land professionals have reviewed title records or other title review materials relating to substantially all of our producing properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. A title opinion obtained on the drill site prior to drilling does not necessarily ensure satisfactory title. We believe we have satisfactory title to all our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. At June 30, 2009, our leaseholds for some of our net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination. In the normal course of our business, title defects of varying degrees will arise, and, if practicable, reasonable efforts will be made to cure any such defects.
The Company may make acquisitions of oil and gas properties from time to time subject to available resources. In making an acquisition, we generally focus most of our title and valuation efforts on the more significant properties. It is generally not feasible for us to perform an in-depth review of every property we purchase and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and we may decide to assume environmental and other liabilities in connection with acquired properties.
We are subject to various governmental regulations which may cause us to incur substantial costs.
Our operations are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
Sales of natural gas by us are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Sales of our natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations that normally attend sales of commodity products.
Since the mid-1980s, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B and 636-C (“Order 636”), that significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the
unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the FERC’s purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, and the courts have largely upheld Order 636. Because further review of certain of these orders is still possible, and other appeals may be pending, it is difficult to predict the ultimate impact of the orders on us and our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our natural gas, although it may also subject us to greater competition, more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1997, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect us only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. We cannot predict what action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.
The price we receive from the sale of oil is affected by the cost of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are not able to predict with certainty the effect, if any, of these regulations on our operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil.
The ultimate impact of the complex rules and regulations issued by the FERC since the mid-1980s cannot be predicted. We cannot predict what further action the FERC will take on these matters. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.
Additional proposals and proceedings that might affect the natural gas industry are frequently made before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; and there have been indications that future regulatory efforts might become more vigorous, possibly resulting in more stringent regulation.
Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.
The States of Texas and Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and
production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of these states limit the rate at which oil and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.
We are subject to various environmental risks which may cause us to incur substantial costs.
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us. The impact of such changes, however, would not likely be any more burdensome to us than to any other similarly situated oil and gas company.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We generate typical oil and gas field wastes, including hazardous wastes that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. The United States Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.
The Oil Pollution Act (“OPA”) imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The “responsible party” includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. The OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by the OPA. The OPA also imposes financial responsibility
requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions.
We own or lease properties that for many years have produced oil and gas. We also own natural gas gathering systems. It is not uncommon for such properties to be contaminated with hydrocarbons. Although we or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require us to remove any such wastes or to remediate the resulting contamination. All of our properties are operated by third parties over whom we have limited control. Notwithstanding our lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.
We may be responsible for additional costs in connection with abandonment of properties.
We are responsible for payment of plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that the ultimate aggregate salvage value of lease and well equipment located on our properties will exceed the costs of abandoning such properties. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with the abandonment of any of our properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
A description of our properties is included in “Part I. Item 1. Business” and is incorporated herein by reference.
Item 3.
Item 3. Legal Proceedings.
There are no material legal proceedings to which the Company is a party or to which its properties are subject.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
The Company held its Annual Meeting of Shareholders on April 24, 2009. As of March 6, 2009, the record date for the meeting, 62,570,654 shares of common stock were issued and outstanding. A quorum of 50,638,054 shares of common stock was present or represented at the meeting.
The following individuals were nominated and elected to serve as directors until the Company’s Annual Meeting of Shareholders in 2010:
Calvin A. Wallen, III (Chairman), Gene C. Howard, Herbert A. Bayer, Bob L. Clements, Jon S. Ross, Phyllis K. Harding, and William L. Bruggeman, Jr.
The Shareholders voted as follows on the following matters:
1) Election of Directors. The voting results for each of the nominees were as follows:
2) Ratification of the Board of Directors’ selection of Philip Vogel as the Company’s independent registered public accountants for the fiscal year ending June 30, 2009. The voting results were as follows:
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Common Stock and Market
The common stock of the Company is traded on the NYSE Amex, LLC (the “Exchange”) under the trading symbol “QBC”. Prior to August 4, 2008, the common stock of the Company was traded on the Over-The-Counter Bulletin Board (the “OTCBB”) under the trading symbol “QBIK”.
At September 4, 2009, there were 64,674,565 shares of common stock outstanding held by approximately 813 shareholders of record.
Under its Articles of Incorporation, as amended, the Company is authorized to issue one class of up to 100,000,000 common shares, par value $0.05 per share, and one class of up to 10,000,000 preferred shares, par value $0.01 per share. As of September 4, 2009, there were no preferred shares of the Company outstanding.
Common Stock Price Range
The following table shows, for the periods indicated, the range of high and low bid price information for our common stock as reported by the OTCBB through August 3, 2008, and thereafter the high and low sales price information on the Exchange. Any market for our common stock should be considered sporadic, illiquid and highly volatile. Prices on the OTCBB reflect inter-dealer quotations, without adjustment for retail markup, markdowns or commissions, and may not represent actual transactions. Our common stock’s trading range during the periods indicated is as follows:
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Through the following exercises of warrants, we issued an aggregate of 3,482,500 shares of common stock, which were not registered under the Securities Act of 1933, as amended, during fiscal 2009. Aggregate proceeds to the Company of the aforementioned stock issuances were $2,495,952, all of which have been or is expected to be used for working capital purposes. The aforementioned issuances were made in reliance upon an exemption from registration set forth in Section 4(2) of the Securities Act of 1993, as amended, which exempts transactions by an issuer not involving a public offering.
We did not purchase any of our equity securities during the fourth quarter of fiscal 2009.
Shareholder Return Performance Graph
The following graph compares the cumulative total shareholder return on our common stock during the five years ended June 30, 2009 with the cumulative total shareholder return of the Russell 2000 Index and a peer group of 16 oil and gas exploration and production companies comprised of Abraxas Petroleum Corporation (AXAS), The Meridian Resources Corporation (TMR), GMX Resources Inc. (GMXR), Petrohawk Energy Corporation (HK), Chesapeake Energy Corporation (CHK), Goodrich Petroleum Corporation (GDP), Northern Oil & Gas Inc. (NOG), Comstock Resources Inc. (CRK), EXCO Resources Inc. (XCO), Penn Virginia Corporation (PVA), XTO Energy Inc. (XTO), Quicksilver Resources Inc. (KWK), Range Resources Corporation (RRC), Encore Acquisition Company (EAC), Plains Exploration & Production Company (PXP), and St. Mary Land and Exploration Company (SM) (collectively referred to as the “Peer Group Index”). The comparison assumes an investment of $100 on June 30, 2004 in each of our common stock, the Russell 2000 Index and the Peer Group Index.
Dividend Policy
We have neither declared nor paid any dividends on our common stock since our inception. Presently, we intend to retain our earnings, if any, to provide funds for expansion of our business. Therefore, we do not anticipate declaring or paying cash dividends on our common stock in the foreseeable future. Any future dividends will be subject to the discretion of our Board of Directors and will depend upon, among other things, future earnings, our operating and financial condition, our capital requirements, debt obligation agreements, general business conditions and other pertinent facts. Moreover, the terms of the Credit Facility prohibit the payment of dividends.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of June 30, 2009 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:
Item 6.
Item 6. Selected Financial Data.
The following table presents a summary of our financial information for the periods indicated. It should be read in conjunction with our Financial Statements and related notes (beginning on page at the end of this report) and other financial information included herein.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to assist in an understanding of the Company’s historical financial position and results of operations for each year in the three-year period ended June 30, 2009. The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contains additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
General
The Company’s future results of operations and growth are substantially dependent upon (i) its ability to acquire or find and successfully develop additional oil and gas reserves and (ii) the prevailing prices for oil and gas. We have identified numerous locations to pursue additional drilling. If we are unable to economically complete additional producing wells, the Company’s oil and gas production, and thus its revenues, would likely decline gradually as its reserves are depleted. In addition, oil and gas prices are dependent upon numerous factors beyond the Company’s control, such as economic, political and regulatory developments and competition from other sources of energy. The oil and gas markets have historically been very volatile, and any significant and extended decline in the price of oil or gas would have a material adverse effect on the Company’s financial condition and results of operations, and could result in a further reduction in the carrying value of the Company’s proved reserves and adversely affect its access to capital.
Overview
Cubic Energy, Inc. is an independent upstream energy company engaged in the development and production of, and exploration for, crude oil and natural gas. Our oil and gas assets and activities are concentrated exclusively in Louisiana and Texas.
Our corporate strategy with respect to our asset acquisition and development efforts was to position the Company in a low risk opportunity while building main stream high yield reserves. The acquisition of our Cotton Valley acreage in DeSoto and Caddo Parishes, Louisiana, puts us in a reservoir rich environment both in the Cotton Valley and Bossier/Haynesville Shale formations, which we believe gives us the potential to discover additional commercial horizons that can add value to the bottom line. We have had success on our acreage with wells drilled by achieving production from not only the Cotton Valley and Bossier/Haynesville Shale formations, but also the Hosston formations.
Fiscal 2009 was a challenging year in many aspects.
As of June 30, 2009, the Company has successfully drilled 22 wells in its northwest Louisiana properties (12 in its Johnson Branch acreage in Caddo Parish, and 10 in its Bethany Longstreet acreage in Caddo and DeSoto Parishes). In its Johnson Branch acreage, Cubic has drilled 12 wells through the Cotton Valley sandstones, with three of these wells penetrating deeper into the Bossier/Haynesville shales. Two of such Bossier/Haynesville wells have been completed and are producing from the Haynesville formation; the third such well was completed and is producing from the Cotton Valley formation. To date, 10 Johnson Branch wells have been completed as hydrocarbon producers in the Cotton Valley sandstones. Additionally, in its Bethany Longstreet acreage, Cubic has eight producing wells in the Cotton Valley and Hosston formations and two producing wells in the Haynesville Shale.
During the first quarter of fiscal 2009, the Company elected to participate in the horizontal drilling of Chesapeake Energy’s S Mitchell 12-15-16H1 and Clingman 11-15-15H1 wells. These wells are located in the Johnson Branch and Caspiana Fields of Caddo Parish, Louisiana, and are horizontally drilled to an approximate measured depth of 16,500 feet, followed by a Haynesville Shale completion. Cubic has an estimated 2.5% working interest in the wells. Cubic has a working interest with Chesapeake Energy in three Johnson Branch Cotton Valley wells: the Copeland 12-1 and the Fiest 21-1. We are also participating in these Haynesville horizontal wells: the Clingman 11 H-1, the Clingman 2 H-1 and the Woolworth 15 H-1. Cubic’s future plans include participation in the Beauregard 21-1, and other wells in sections controlled by Chesapeake Energy, Goodrich Petroleum and Petrohawk Energy, in which Cubic has a working interest in the Haynesville Shale.
Participating in these wells is expected to give Cubic’s technical personnel valuable insights in the methods and technologies to help the Company in developing and enhancing the development of the balance of our acreage.
During the second quarter of fiscal 2009, the Company retained RBC Richardson Barr Securities, Inc., to assist the Company in exploring the sale of the Company, or substantially all of its assets. The initial interest in the Company’s assets was very positive. As natural gas prices continued their downward spiral in the beginning of fiscal 2009, it became apparent to management that a bid reflecting the full value of the Company’s assets would not be forthcoming.
Our financial results depend upon many factors, but are largely driven by the volume of our natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we obtain and expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
During the second half of fiscal 2009, oil and natural gas prices declined significantly in response to the worldwide credit crisis, the turmoil in the global financial system and the economic recession in the United States and in other developed and developing countries. In response to natural gas prices during the last quarter of fiscal 2009, we reduced and refocused our 2009 capital budget on the development of non-proved locations in our Bossier/Haynesville shale locations. Our future drilling plans are subject to change based upon various factors, some of which are beyond our control, including drilling results, natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our drilling plans and associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.
Another consequence we face as a result of declining natural gas prices is the possibility that we may be required to recognize a non-cash impairment expense under the full cost method of accounting, which we use to account for our oil and natural gas exploration and development activities. We had recorded a full cost ceiling impairment of approximately $20.4 million at June 30, 2009, at which time the Henry Hub spot market price was $3.72 per MMbtu for natural gas. If natural gas prices do not recover, we may be required to take additional impairment charges in the future.
In March 2009, the Company began a strategic campaign to pursue three options. First, restructure our debt and operating capital. This plan seeks to provide the capital needed for drilling seven to ten horizontal wells during 2010-2011. Second, pursue a joint venture with a larger company that could assist with operations and allow the Company to maintain a working interest and become a financially strong public company. The third
option would be to sell the Company or its assets. This option is the least attractive to management at this time due to low natural gas prices, which makes it difficult for the Company to realize acceptable shareholder value.
Due to a lack of cash we did very little well workover during fiscal 2009. Without the needed fracture stimulation, natural gas production of the wells continues to fall. As the world economy declined, so did natural gas prices. The natural gas price downward spiral and our lack of cash on hand to stimulate well production caused the Company to have impairment losses for each of the first three quarters of fiscal 2009. While it created difficulties for operations, it provided a fortuitous situation in that we were not drilling and producing gas for sale into this depressed natural gas market.
As shown in the accompanying financial statements, the Company incurred a net loss of $24,762,516 during the year ended June 30, 2009, and as of that date, the Company’s current liabilities exceeded its current assets by $27,822,536 and its total liabilities exceeded its total assets by $16,022,965. Those factors, as well as the uncertain conditions that the Company faces regarding its loan agreements (as discussed in Note E), create an uncertainty about the Company’s ability to continue as a going concern. Management of the Company has developed a plan to reduce its liabilities through additional financing and issuance of additional stock to shareholders. The Company’s plan includes several strategic opportunities to correct the current financial situation. The Company is involved in negotiations that could provide up to $40,000,000 in drilling credits, expand it Credit Facility to $40,000,000 from its current full utilized $25,000,000 facility and extend the term of the facility out two to three years beyond the current maturity date of March 1, 2010. The ability of the Company to continue as a going concern is dependent on acceptance of the plan by the Company’s bank creditors and the plan’s success. The financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
Management continues to believe in the value of its assets and will pursue all options that allow the Company to leverage those assets to gain full shareholder value.
Summary Operating, Reserve and Other Data
The following table presents an unaudited summary of certain operating and oil and natural gas reserve data, and non-GAAP financial data for the periods indicated:
RESULTS OF OPERATIONS
Comparison of Fiscal 2009 to Fiscal 2008
Revenues
OIL AND GAS SALES decreased 19% to $1,858,139 for fiscal 2009 from $2,302,310 for fiscal 2008 primarily due to lower gas volumes resulting from a steep production decline-curve and lack of funds to workover existing wells and a 34% decrease in the weighted average sales price for gas (per Mcf). This decline was mitigated by the Company having an average of approximately 22 (gross) wells on-line in Louisiana in fiscal 2009 versus approximately 13 (gross) wells in fiscal 2008.
Costs and Expenses
OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) increased 18% to $1,372,041(74% of oil and gas sales) for fiscal 2009 from $1,162,489 (50% of oil and gas sales) for fiscal 2008 primarily due to more wells being on-line in Louisiana, which resulted in: $104,002 increase in common facility expenses, a $101,272 increase in chemical cost and a $64,892 increase in salt water hauling costs. These increases were somewhat offset by a $102,366 decrease in costs passed-through to the Company by the purchaser of the Company’s gas. Such costs are deducted from the Company’s gross revenue by the purchaser.
GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) decreased 22% to $1,940,025 for fiscal 2009 from $2,488,133 in fiscal 2008 as a result of: a $857,099 decrease in non-cash stock compensation expense due to a 68% decrease in the number of shares of common stock granted versus the prior year period. This decrease was somewhat offset by a $135,536 increase in corporate fees paid, which includes $115,042 in AMEX listing fees and a $4,000 increase due to adding two more outside directors, a $48,563 increase in legal fees due in part to the support needed to address the NYSE Amex non-compliance issue; and $116,870 in contract services fees related to management’s transition to a new chief financial officer, which occurred in fiscal 2009, but did not occur in the prior year period.
DEPRECIATION, DEPLETION AND AMORTIZATION (“DD&A”) decreased 279% to $771,861in fiscal 2009 from $2,152,096 in fiscal 2008 primarily due to a decrease in capital expenditures in fiscal 2009 related to the acquisition and development of oil and gas properties.
IMPAIRMENT OF OIL AND GAS PROPERTIES increased to $20,390,819 in fiscal 2009 from $0 in fiscal 2008. The fiscal 2009 impairment resulted from a downward revision of our reserve estimates, which was effected by the following events: (i) we experienced delays related to third party providers in our Bethany Longstreet acreage, including not receiving contracted-for compression services, which temporarily delayed our ability to produce from these wells; (ii) we did not effectuate final completion of certain wells due to a shift in our focus to the development of our Johnson Branch acreage in Caddo Parish, Louisiana; and, (iii) the lack of production history in wells recently brought online lead to a sharper decline curve being utilized by RPS Scotia, Inc. in formulating the reserve estimates.
INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 29% to $2,044,718 in fiscal 2009 from $1,579,452 in fiscal 2008 primarily due to an increase in debt (before discounts) to $27,000,000 at June 30, 2009 from $23,827,800 at June 30, 2008. This increase resulted from the drawing down of our revolving credit line of $3,172,200 (before discounts). The weighted average debt balance (before discounts) for fiscal 2009 was $26,565,452 as compared to $16,494,613 in fiscal 2008. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $514,620 being recorded in fiscal 2009 as compared to $516,030 in fiscal 2008. There was a decrease in the capitalization of
interest expense to the full cost pool for oil and gas properties of $30,682 in fiscal 2009 as compared to $330,608 in fiscal 2008.
Comparison of Fiscal 2008 to Fiscal 2007
OIL AND GAS SALES increased 295% to $2,302,310 for fiscal 2008 from $583,416 for fiscal 2007 primarily due to higher gas volumes resulting from an average of approximately 13 (gross) wells being on-line in Louisiana in fiscal 2008 versus approximately three and one-half wells in fiscal 2007, and a 21% increase in the weighted average sales price for gas (per Mcf).
Costs and Expenses
OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) increased 142% to $1,162,489 (50% of oil and gas sales) for fiscal 2008 from $481,145 (82% of oil and gas sales) for fiscal 2007 primarily due to more wells being on-line in Louisiana, which resulted in: a $307,551 increase in salt water hauling and disposal costs; $126,992 in common facility expenses for production from the Company’s Johnson Branch wells, which did not occur in the prior year period; a $46,470 increase in contract labor costs; a $41,998 increase in state taxes on production (also referred to as “severance taxes” elsewhere herein); and a $156,998 increase in costs passed-through to the Company by the purchaser of the Company’s gas. Such costs are deducted from the Company’s gross revenue by the purchaser and include, but are not limited to: costs to market the Company’s gas, compression fees, and the cost of fuel used by the purchaser to convey the Company’s gas. These increases were somewhat offset by a $79,867 drop in non-recurring workover expenses.
GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) increased 88% to $2,488,133 for fiscal 2008 from $1,325,192 in fiscal 2007 as a result of: a $765,537 increase in non-cash stock compensation expense related primarily to appreciation of the Company’s common stock price, a 29% increase in the number of shares of common stock granted versus the prior year period, and full recognition in fiscal 2008 of stock compensation issued during that year, which vested immediately with no forfeiture provisions, rather than amortization over the four quarters of the service period; a $141,689 increase in cash compensation expense resulting from an increase in the number of employees; a $39,583 increase in reserve report expenses; a $15,428 increase in fees paid to our outside directors; and the following expenses, which occurred in fiscal 2008 but did not occur in the prior year period: $60,000 in contracted professional services fees related to management’s assessment of the Company’s internal controls over financial reporting required by Section 404(a) of the Sarbanes-Oxley Act of 2002; $76,507 in marketing expenses; $51,030 in expense for directors’ and officers’ insurance; and, $23,082 in corporate fees related to the Company’s annual shareholders’ meeting. These increases were partially offset by a $36,279 decrease in legal fees due to non-recurrence of: the preparation of documents and filings related to a private placement of shares of the Company’s common stock in December 2006 and the transacting of the March 2007 debt issue.
DEPRECIATION, DEPLETION AND AMORTIZATION (“DD&A”) increased 494% to $2,152,096 in fiscal 2008 from $362,434 in fiscal 2007 primarily due to an $11,281,505, or 278%, increase in capital expenditures in fiscal 2008 related to the acquisition and development of oil and gas properties.
IMPAIRMENT OF OIL AND GAS PROPERTIES decreased to $0 in fiscal 2008 from $1,790,882 in fiscal 2007. The fiscal 2007 impairment resulted from a downward revision of our reserve estimates, which was effected by the following events: (i) we experienced delays related to third party providers in our Bethany Longstreet acreage, including not receiving contracted-for compression services, which temporarily delayed our ability to produce from these wells; (ii) we did not effectuate final completion of certain wells due to a shift in our focus to the development of our Johnson Branch acreage in Caddo Parish, Louisiana; and, (iii) the lack of production history in wells recently brought online lead to a sharper decline curve being utilized by RPS Scotia, Inc. in formulating the reserve estimates.
INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 24% to $1,579,452 in fiscal 2008 from $1,278,721 in fiscal 2007 primarily due to an increase in debt (before discounts) to $23,827,800 at June 30, 2008 from $9,000,000 at June 30, 2007. This increase resulted from the repayment of a $1,300,000 note held by Tauren on February 2, 2007 from the proceeds of a December 2006 equity offering, and the retirement of $5,500,000 of indebtedness held by Petro Capital V. L.P. on March 5, 2007 via the borrowing of $5,000,000 pursuant to the aforementioned Wells Fargo Credit Facility’s senior convertible term loan, subsequent draws of approximately $16,827,800 on a related revolving line of credit, and the borrowing of $2,000,000 under the terms of the May 6, 2008 Subordinated Note. The weighted average debt balance (before discounts) for fiscal 2008 was $16,494,613 as compared to $6,467,579 in fiscal 2007. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $516,030 being recorded in fiscal 2008 as compared to $164,961 in fiscal 2007. Such increases were somewhat offset by the capitalization of interest expense to the full cost pool for oil and gas properties of $330,608 in fiscal 2008 as compared to zero in fiscal 2007.
LOSS ON EXTINGUISHMENT OF DEBT was $0 in fiscal 2008 as compared to $1,082,887 in fiscal 2007 due to there being no retirement of debt in fiscal 2008. On March 5, 2007, the senior debt held by Petro Capital was retired with proceeds from the Credit Facility with Wells Fargo. In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(1,082,887) in fiscal 2007. Such amount included the write-off of deferred loan costs ($235,898), and the write-off of the remaining loan discount ($846,989).
Liquidity and Capital Resources
Overview
The Company’s primary resource is its oil and gas reserves. The Company has entered into a senior credit facility, but the Company will be required to make significant repayments of amounts borrowed by November 1, 2009, as a result of a re-determination in the borrowing base on the revolving credit facility, primarily due to lower commodity prices.
On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo providing for the Credit Facility, which consists of a convertible term loan of $5,000,000 and a revolving credit facility of $20,000,000 in order to fund the drilling and completion of new wells. On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation (see “Notes to Financial Statements - Note E - Long-term debt” elsewhere herein).
On June 29, 2009, we received a letter from Wells Fargo Energy Capital, Inc. (the “Lender”) informing the us that the Lender has made a redetermination of the borrowing base, which reduced the borrowing base from $20.0 million to $7.5 million, requiring a payment of $12.5 million from the Company to the Lender. Through waiver, the Lender originally extended the date for the payment until September 1, 2009. This date has been extended to November 1, 2009 and we have the right to pay the deficiency in five monthly installments as provided in our Credit Agreement with the Lender. If the Company is not successful in renegotiating this agreement the Lender can foreclose on our assets. The Company is working closely with the Lender to assist in avoidance of such actions.
Product prices, over which we have no control, have a significant impact on revenues from production and the value of such reserves and thereby on the Company’s borrowing capacity in the event the Company determines to borrow additional funds. Within the confines of product pricing, the Company must be able to find and develop or acquire oil and gas reserves in a cost effective manner in order to generate sufficient financial resources through internal means to complete the financing of its capital expenditure program.
During the twelve months ended June 30, 2009, the Company used cash flows from operating activities of $2,152,187 as compared to $1,233,829 in fiscal 2008. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.
Working Capital and Cash Flow
The Company’s working capital decreased to ($27,822,536) at June 30, 2009 from $1,746,741 at June 30, 2008. This decrease was primarily due to $27,000,000 of debt scheduled to mature on March and April 2010, becoming a part of current liabilities during the quarter ended March 31, 2009 and year ended June 30, 2009. The downturn in the price for natural gas lowered revenue This reclassification was partially offset by cash flows provided by financing activities of $5,668,152 resulting from $2,495,952 of proceeds from the issuance of common stock (as a result of the exercise of warrants), and the borrowing of $3,172,200 on the aforementioned revolving line of credit with Wells Fargo in fiscal 2009.
The Company anticipates the following capital expenditures in the remainder of fiscal 2010: re-completions of up to four wells in its Johnson Branch acreage; the acquisition of additional leaseholds in and around its core acreage position; final payments that may be outstanding as a result of the acquisition of rights-of-way in certain of our leases; and the election to participate in certain horizontal Haynesville Shale wells operated by an unrelated third-party, which began production during the year ending June 30, 2009. As a result, our projected capital expenditures are expected to be in a range of approximately $3,000,000 to $40,000,000 for fiscal 2010. Any significant capital expenditures will depend on obtaining additional funds and restructuring our current indebtedness.
Due to the significant downturn in the price of natural gas, continued prudence will be exercised in the undertaking of any new operations during the near term. No assurance can be given that all or any of these anticipated projects will be completed as currently anticipated. While the Company is negotiating with Wells Fargo to expand its Revolving Note and extend the maturity date, we currently have very little cash on hand and our ability to continue to meet our obligations and fund the projected capital expenditure at this time is not certain for fiscal 2010.
Additionally, because future cash flows and the availability of borrowings are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company’s success in developing and producing new reserves, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company’s development and exploration program, there can be no assurance that the Company’s capital resources will be sufficient to sustain the Company’s development and exploration activities.
The Company’s working capital decreased to $1,746,741 at June 30, 2008 from $2,606,796 at June 30, 2007, primarily due to capital expenditures of $15,341,903 related to the drilling and completion of new wells and the aforementioned $1,233,829 use of cash from operating activities in fiscal 2008. These uses of cash were somewhat offset by the borrowing of $12,827,800 on the aforementioned revolving line of credit with Wells Fargo, the borrowing of $2,000,000 under the aforementioned subordinated promissory note issued to Diversified Dynamics Corporation and $1,110,295 in proceeds from the issuance of stock, resulting from the exercise of warrants, during fiscal 2008.
Capital Expenditures
The majority of our oil and gas reserves are undeveloped. As such, recovery of the Company’s future undeveloped proved reserves will require significant capital expenditures. Our management estimates that aggregate capital expenditures ranging from a minimum of approximately $3,000,000 (from currently available funds and projected cash from operating activities) to a maximum of approximately $40,000,000 (subject to the availability of additional financing) will be made to further develop these reserves during fiscal 2010. Moreover, additional capital expenditures may be required for exploratory drilling on our
undeveloped acreage. The Company may increase its planned activities for fiscal 2010 if product prices improve and if we are able to obtain the additional capital resources necessary to finance such activities. However, to the extent that: i) we are not able to renegotiate our Revolving Note with Wells Fargo; ii) we are not able to raise additional capital; or iii) drilling rigs, drill pipe and other material used in oil and gas drilling and completing are unavailable, our capital expenditures will be restricted.
Capital Resources
The Company plans to fund its development and exploratory activities through cash on hand (which was approximately $500,000 as of the date of this filing), cash provided from operations; the potential exercises of warrants for cash; and one of, or a combination of, the following potential transactions: a private placement of common stock; a public offering of common stock; a joint venture with a more well-financed industry partner in which we would farm-out a to-be-determined percentage of our working interests in certain properties; or a disposition of assets.
While we expect production from the wells drilled and completed in fiscal 2007, 2008, 2009 and subsequent to the end of fiscal 2009 to provide cash flow to support additional drilling in fiscal 2010, the Company cannot be certain that adequate funds will be available from cash on hand, operating cash flow, the exercise of warrants, and the aforementioned potential transactions to fully fund the projected capital expenditures for fiscal 2010. Additionally, because future cash flows, the availability of borrowings, and the ability to consummate the aforementioned potential transactions are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company’s success in developing and producing new reserves, the uncertainty of financial markets and joint venture and merger and acquisition activity, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company’s development and exploration program, there can be no assurance that the Company’s capital resources will be sufficient to sustain the Company’s development and exploratory activities.
Although the Company believes it will be able to obtain funds pursuant to the above-mentioned alternatives, management cannot be assured that such capital resources will be available to the Company. If we are unable to obtain such capital resources on a timely basis, the Company may curtail its planned development and exploratory activities.
Critical Accounting Policies
The preparation of our financial statements requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of our accounting estimates and judgments that management believes are most significant in its application of generally accepted accounting principles used in the preparation of the financial statements.
Impairment of long-lived assets and long-lived assets to be disposed of
The Company has adopted the provisions of the Financial Accounting Standards Board’s (the “FASB”) Statement of Financial Accounting Standards (“FAS”) No. 144 (“FAS No. 144”), Accounting for the Impairment or Disposal of Long-Lived Assets, effective for periods beginning July 1, 2002, and thereafter. FAS No. 144 replaces FAS No. 121, and, among other matters, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. FAS No. 144 retains the basic provisions of FAS No. 121, but broadens its scope and establishes a single model for long-lived assets to be disposed of by sale. In addition, the Company is subject to the rules of the Securities and Exchange Commission with respect to
impairment of oil and gas properties accounted for under the full cost method of accounting, as described below.
Full cost method of accounting for oil and gas properties
The Company has adopted the full cost method of accounting for oil and gas properties. Management believes adoption of the full cost method more accurately reflects management’s exploration objectives and results by including all costs incurred as integral for the acquisition, discovery and development of whatever reserves ultimately result from its efforts as a whole. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs related to exploratory and development activities, and directly related overhead costs, are capitalized into the full cost pool.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
In addition, the capitalized costs are subject to a “full cost ceiling test,” which generally limits such costs to the aggregate of the “estimated present value” (discounted at a 10 percent (10%) interest rate) of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
Oil and gas revenues
The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Differences between sales and production volumes during the years ended June 30, 2009, 2008 and 2007 were not significant.
Use of estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Certain significant estimates
Management’s estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.
Stock-based compensation
The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This FAS requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2007.
Subsequent Events
In May 2009, the FASB issued SFAS No. 165 “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 sets forth (1) The period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) The circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) The disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009. The adoption of this statement did not have a material effect on the Company’s financial statements.
Other Accounting Policies and Recent Accounting Pronouncements
Please see “Notes to Financial Statements - Note B - Significant accounting policies” elsewhere herein.
Inflation
Although the level of inflation affects certain of the Company’s costs and expenses, inflation did not have a significant effect on the Company’s results of operations during fiscal 2009.
Related Party Transactions
A description of our related party transactions is included in “Note F - Related party transactions” in the Notes to the Financial Statements of the Company included elsewhere in this Report, and is incorporated herein by reference.
Off-Balance Sheet Arrangements
We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Reductions in crude oil, natural gas and natural gas liquids prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to price fluctuations, can adversely affect our liquidity and our ability to obtain capital for our acquisition and development activities. To date, we have not entered into futures contracts or other hedging agreements to manage the commodity price risk for a portion of our production.
Interest Rate Risk
As of June 30, 2009, we had $27,000,000 of long-term debt outstanding under our Credit Facility and the Subordinated Note, each of which matures in fiscal 2010 and bears interest at the prime rate plus 2.0%. As a result, our interest costs fluctuate based on short-term interest rates. Based on the aforementioned borrowings outstanding at June 30, 2009, a 100 basis point change in interest rates would change our annual interest expense by approximately $270,000. We had no interest rate derivatives during fiscal 2009.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The Report of Independent Accountants, Financial Statements and any supplementary financial data required by this Item are set forth on pages through of this Report and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a - 15(f) and 15d - 15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an assessment, including testing, of the effectiveness of our internal control over financial reporting as of June 30, 2009 based on the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our system of internal control over financial reporting is 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. 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 the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
Based on our evaluation under the criteria set forth in Internal Control-Integrated Framework, our management concluded that our internal control over financial reporting was effective as of June 30, 2009. This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. We were not required to have, nor have we engaged our independent registered public accounting firm to perform, an audit on our internal control over financial reporting pursuant to the rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report.
Changes in Internal Control Over Financial Reporting
Subsequent to our evaluation, there were no changes in internal controls or other factors that could materially affect, or are reasonably likely to materially affect, these internal controls. We maintain a system of internal control over financial reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations on Internal Control
A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
Certifications
Our chief executive officer and chief financial officer have completed the certifications required to be filed as an Exhibits to this Report (see Exhibits 31.1 and 31.2) relating to the design of our disclosure controls and procedures and the design of 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.
Directors and Executive Officers
The following table provides information concerning each of our executive officers and directors as of September 3, 2009:
CALVIN A. WALLEN, III has served as the President and Chief Executive Officer of the Company since December 1997, and as Chairman of the Board of Directors since June 1999. Mr. Wallen has over 20 years of experience in the oil and gas industry working as a drilling and petroleum engineer. Prior to joining Cubic, Mr. Wallen was employed by Superior Oil and various other drilling contractors including Resource, Tom Brown and Rowan International. Mr. Wallen assisted in the design and construction of several land rigs with advanced drilling systems and has domestic and international experience in drilling engineering. While employed by Rowan International, Mr. Wallen gained experience in drilling high angle directional wells at Prudhoe Bay on contract to Arco. In 1982, Mr. Wallen began acquiring and developing oil and gas properties, forming a production company that has evolved into Tauren Exploration, Inc. Mr. Wallen attended Texas A&M University at College Station, Texas.
LARRY G. BADGLEY joined the Company in August 2008, as a consultant, and was appointed Chief Financial Officer in October 2008. Prior to joining the Company, from October 2005 through September 2006, Mr. Badgley served as Managing Director of BridgePoint Consulting, a provider of CFO services to venture capital-backed and early stage companies. In that capacity, Mr. Badgley was primarily responsible for strategic planning for growth companies. From July 1998 through October 2005, Mr. Badgley served as Director of Accounting and Finance for Jefferson Wells International, an international professional services firm. Prior to that time, Mr. Badgley served as Chief Operating Officer and Chief Financial Officer of a privately held national sign manufacturer until its sale in July 1998. Mr. Badgley received a BBA in Finance from Hardin-Simmons University and is a Certified Public Accountant.
JON S. ROSS has served as a director of the Company since April 1998 and as Secretary since November 1998. Since 1989, Mr. Ross has been a practicing attorney in Dallas, Texas representing over 80 business entities. He has served on several community and not-for-profit committees and boards and has been asked to speak to corporate and civic leaders on a variety of corporate law topics. Mr. Ross graduated from St. Mark’s School of Texas with honors in 1982 and graduated from the University of Texas at Austin in 1986 with a
B.B.A. in Accounting. He then graduated from the University of Texas School of Law in 1989 attaining a Juris Doctorate degree.
GENE C. HOWARD is the Senior Partner of the law firm of Howard, Widdows, and Bufogle, P.C. of Tulsa, Oklahoma and has been engaged primarily in the private practice of law over the past thirty-five years. Mr. Howard served in the Oklahoma State Senate from 1964 through 1982 and was President Pro Tem from 1975 through 1981. In addition, he served as the Chairman of the Board of Farmers and Exchange Bank from 1972 through 1991 and on the Board of Directors of Local Federal Bank of Oklahoma. Mr. Howard is a Director of the Oklahoma State Education and Employment Group Insurance Board and presently acts as Chairman. Mr. Howard served as Director of EntreCap Financial Corporation and Hinderliter Construction, Inc. from 1991 to August of 1992.
HERBERT A. BAYER has served as a director of the Company since May 2003. From 2006 to 2008, Mr. Bayer served as Global Director of Wi-Fi and Municipal Markets for SmartSynch, Inc., which provides GPRS and Wi-Fi Smart Metering Technology for Smart Grid Deployments for the electric utility industry. Prior to joining SmartSynch, Mr. Bayer served as Director of Client Services for CH2M HILL, an engineering, construction and operations company, from 2005 to 2006, and National Director of Sales for Hexagram Inc. from 2003 to 2005. During his career, Mr. Bayer has worked with investor-owned utilities, government-run municipalities and electric cooperatives. His work experience includes work in Electronic Meter Reading, Automatic Meter Reading, Load Research, Internet Applications, and Wi-Fi Network Systems. Mr. Bayer’s major course of study at Indiana State University was Business Management.
BOB L. CLEMENTS joined the Company’s board of directors in February 2004. Mr. Clements has been in the wholesale food and restaurant business for over thirty years, currently controlling the largest independent producer of stuffed jalapenos and corn dogs as well as two successful restaurants in the Rockwall, Texas area. Mr. Clements has served and currently serves on a variety of not-for-profit and charitable committees and boards. Mr. Clements has a degree in the OPM Program from the Harvard Business School.
PHYLLIS K. HARDING joined the Company’s board in April 2009. Ms Harding has worked as an executive advisor for Diversified Dynamics Corporation, a privately held corporation controlled by William L. Bruggeman, Jr., since 1990. From 2001 through 2008 she served on the Board of Directors of Dayport, a leader in video publishing, content, workflow and syndication solutions. Dayport was acquired by EntriQ in 2008. From 2001 to the present time she has served on the Board of Advisors of Geospan Corporation and Geospan.com, privately held industry leaders in spatial imaging and visual mapping solutions. She has worked with numerous corporations in various industries as the head of the consulting division for Grant Thornton LLP in Minneapolis from 1987 through 1988 and as a co-owner of Camelot Consultants, Inc. from 1989 through 1999. Ms. Harding has three decades of operational, manufacturing, turn-around and strategic leadership experience with various clients and direct employment at The Valspar Corporation (1986 through 1987) and Procter & Gamble (1975 through 1986). She is a graduate of the University of Wisconsin - Green Bay.
WILLIAM L. BRUGGEMAN, JR. joined the Company’s board in April 2009. Mr. Bruggeman is the founder and controlling shareholder of Diversified Dynamics Corporation (founded in 1968) and its business divisions: Cat Pumps, a manufacturer of quality, industrial, positive displacement, triplex piston and plunger pumps and custom engineered pumping systems with over 40 years of experience in industrial high pressure systems; and HomeRight, a manufacturer of home improvement products. He is an entrepreneur and “angel investor” who has been involved in many successful start up businesses. He has been a significant investor in the oil and gas industries since the early 1990s. He continues to be a major shareholder of Cubic Energy, Inc. Mr. Bruggeman’s former employers include McCullough Corporation, John Deere, L & A Products, and Minneapolis Moline. Mr. Bruggeman is a veteran who served thirty months in the U.S. Navy and one year in the U.S. Marine Corp. Mr. Bruggeman graduated from Hamline University with a degree in Engineering.
There are no family relationships among any of the directors or executive officers of the Company. See “Certain Relationships and Related Transactions” for a description of transactions between the Company and its directors, executive officers or their affiliates.
Audit Committee; Financial Expert
The Audit Committee is comprised of Messrs. Howard (Chairman), Clements and Bayer. All of the members of the Audit Committee are “independent” under the rules of the SEC and the NYSE-Amex, LLC. The Board of Directors, after reviewing all of the relevant facts, circumstances and attributes, has determined that Mr. Howard is the sole “audit committee financial expert” on the Audit Committee.
Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Exchange Act requires the Company’s directors, executive officers, and holders of more than 10% of the common stock to file with the SEC reports of ownership and changes in ownership of common stock. SEC regulations require those directors, executive officers, and greater than 10% shareholders to furnish the Company with copies of all Section 16(a) forms they file. Based on the Company’s review of reports, the Company believes that the directors, executive officers, and greater than 10% shareholders complied with all applicable Section 16(a) filing requirements during fiscal 2009.
Code of Ethics
The Company has adopted a Code of Ethics that applies to its directors, officers and employees. The Company will provide a copy of its Code of Ethics, without charge, to any stockholder who makes such request in writing to the Company, attention: Secretary.
Item 11.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
General. Our Board of Directors has established a Compensation Committee, comprised entirely of independent non-employee directors, with authority to set all forms of compensation of our executive officers. Messrs. Bayer, Clements and Howard comprised the Compensation Committee in fiscal 2009, with Mr. Howard serving as its Chairman. The Compensation Committee has overall responsibility for our executive compensation policies as provided in a written charter adopted by the Board of Directors. The Compensation Committee is empowered to review and approve the annual compensation and compensation procedures for our executives: the President and Chief Executive Officer, the Chief Financial Officer, and the Secretary. The Compensation Committee does not delegate any of its functions to others in setting compensation.
When establishing base salaries, cash bonuses and equity grants for each of the executives, the Compensation Committee considers the recommendations of the President and Chief Executive Officer and the Secretary, the executive’s role and contribution to the management team, responsibilities and performance during the past year and future anticipated contributions, corporate performance, and the amount of total compensation paid to executives in similar positions, and performing similar functions, at other companies for which data was available, as provided by third party compensation studies. One such study, published in September 2009 by Salary.com was a blind survey of over 1,000 companies located in the Dallas metropolitan area in the “Energy & Utilities” industry with less than 25 full-time equivalent employees. Another study, published in December 2004, included data from a survey of the following comparable companies: Arena Resources, Inc., ATP Oil & Gas, Berry Petroleum Company, Canadian Superior Energy, Edge Petroleum, Goodrich Petroleum, Infinity Inc., Petroleum Development Corp., The Meridian Resources Corp., and The Exploration Company.
The Compensation Committee relies upon its judgment in making compensation decisions, after reviewing the Company’s performance and evaluating each executive’s performance during the year. The Committee generally does not adhere to formulas or necessarily react to short-term changes in business performance in determining the amount and mix of compensation elements. We incorporate flexibility into our compensation programs and in the assessment process to respond to and adjust for the evolving business environment.
Compensation Philosophy. The Compensation Committee’s compensation philosophy is to reward executive officers for the achievement of short and long-term corporate objectives and for individual performance. The objective of this philosophy is to provide a balance between short-term goals and long-term priorities to achieve immediate objectives while also focusing on increasing shareholder value over the long term. Also, to ensure that we are strategically and competitively positioned for the future, the Compensation Committee has the discretion to attribute significant weight to other factors in determining executive compensation, such as maintaining competitiveness, pursuing growth opportunities and achieving other long-range business and operating objectives. The level of compensation should also allow us to attract, motivate, and retain talented executive officers that contribute to our long-term success. The compensation of our President and Chief Executive Officer and other executive officers is comprised of cash compensation and long-term incentive compensation in the form of base salary, discretionary bonuses and unregistered stock awards.
Elements of Our Compensation Program and Why We Pay Each Element. For fiscal 2009, our total compensation for executive officers consisted of base salary, bonuses and long-term incentives in the form of common stock awards. In setting fiscal 2009 compensation, the Compensation Committee considered the specific factors discussed below:
Base Salary. In setting the executive officers’ base salaries, the Compensation Committee considers the achievement of corporate objectives as well as individual performance. Because the Compensation Committee believes that executive compensation should be viewed in terms of a balanced combination of cash compensation (i.e., base salaries and bonuses) and long-term incentive (i.e., grants of unregistered stock), base salaries are targeted to approximate the low end of the range of base salaries paid to executives of similar companies for each position. To ensure that each executive is paid appropriately, the Compensation Committee considers the executive’s level of responsibility, prior experience, overall knowledge, contribution to business results, existing equity holdings, executive pay for similar positions in other companies, and executive pay within our company.
Base salaries for our named executive officers in fiscal 2009 were as follows:
(1) There were no increases in executive officers base salaries during fiscal 2009
Discretionary Bonuses. Executive bonuses are intended to link executive compensation with the attainment of Company goals. The actual payment of bonuses is primarily dependent upon the extent to which these Company-wide objectives are achieved. Determination of executive bonus amounts is not made in accordance with a strict formula, but rather is based on objective data combined with competitive ranges and
internal policies and practices, including an overall review of both individual and corporate performance. For fiscal year 2009, bonuses to executives were primarily based upon the achievement of certain business objectives including progress in meeting our expected drilling and completion schedule, and obtaining additional financing. The President and Chief Executive Officer has the discretion to recommend to the Compensation Committee to increase or decrease bonuses for all other executive officers, but any bonus amounts must be approved by the Compensation Committee.
Long-Term Incentives. On December 29, 2005, the shareholders of the Company approved the 2005 Stock Option Plan (the “Plan”) under which our executive officers may be, among other forms of compensation, compensated through grants of unregistered shares of our common stock and/or grants of options to purchase shares of common stock. The Compensation Committee approves Plan grants that provide additional incentives and align the executives’ long-term interests with those of the shareholders of the Company by tying executive compensation to the long-term performance of the Company’s stock price. Annual equity grants for our executives are typically approved in January.
The Compensation Committee recommends equity to be granted to an executive with respect to shares of common stock based on the following principal elements including, but not limited to:
· President and Chief Executive Officer’s and Secretary’s recommendations;
· Management role and contribution to the management team;
· Job responsibilities and past performance;
· Future anticipated contributions;
· Corporate performance; and
· Existing equity holdings.
Determination of equity grant amounts is not made in accordance with a formula, but rather is based on objective data combined with competitive ranges, past internal policies and practices and an overall review of both individual and corporate performance. Equity grants may also be made to new executives upon commencement of employment and, on occasion, to executives in connection with a significant change in job responsibility. The Compensation Committee believes annual equity grants more closely align the long-term interests of executives with those of shareholders and assist in the retention of key executives. As such, these grants comprise the Company’s principal long-term incentive to executives.
Other Compensation Policies Affecting the Executive Officers
Compliance with Section 162(m) of the Internal Revenue Code. Section 162(m) disallows a federal income tax deduction to publicly held companies for certain compensation paid to our Named Executive Officers to the extent that compensation exceeds $1 million per executive officer covered by Section 162(m) in any fiscal year. The limitation applies only to compensation that is not considered “performance based” as defined in the Section 162(m) rules. In designing our compensation programs, the Compensation Committee considers the effect of Section 162(m) together with other factors relevant to our business needs. We have historically taken, and intend to continue taking, appropriate actions, to the extent we believe desirable, to preserve the deductibility of annual incentive and long-term performance awards. However, the Compensation Committee has not adopted a policy that all compensation paid must be tax-deductible and qualified under Section 162(m). We believe that the fiscal 2009 base salary, annual bonus and stock grants paid to the individual executive officers covered by Section 162(m) will not exceed the Section 162(m) limit and will be fully deductible under Section 162(m).
Stock Ownership Requirements. The Compensation Committee does not maintain a policy relating to stock ownership guidelines or requirements for our executive officers because the Compensation Committee does not feel that it is necessary to impose such a policy on our executive officers. If circumstances change, the Compensation Committee will review whether such a policy is appropriate for executive officers.
Employment Agreements. On February 29, 2008, the Company entered into employment agreements with its President and Chief Executive Officer, Calvin A. Wallen, III, and Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.
Both agreements provide for a term of employment of 36 months from the effective date of February 1, 2008, which term shall be automatically extended by one additional month upon the expiration of each month during the term; provided, that the Company may terminate subsequent one-month extensions at any time. Each agreement is subject to early termination by the Company in the event that the employee dies, becomes totally disabled or commits an act constituting “Just Cause” under the agreement. The agreements provide that Just Cause includes, among other things, the conviction of certain crimes, habitual neglect of his duties to the Company or other material breaches by the employee of the agreement. Each agreement also provides that the employee shall be permitted to terminate his employment upon the occurrence of “Good Reason,” as defined in the agreement. The agreements provide that Good Reason includes, among other things, a material diminution in the employee’s authority, duties, responsibilities or salary, or the relocation of the Company’s principal offices by more than 50 miles. If the employee’s employment is terminated by (a) the Company other than due to the employee’s death, disability or Just Cause, or (b) the employee for Good Reason, then the Company is required to pay all remaining salary through the end of the then-current term. The foregoing severance payment is subject to reduction under certain conditions.
The following table sets forth the estimated amounts that would be payable to each of the named executives upon a termination under the scenarios outlined above, excluding termination for Just Cause or on account of death or disability, assuming that such termination occurred on June 30, 2009. There can be no assurance that these scenarios would produce the same or similar results as those disclosed if a termination occurs in the future.
(1) Represents 36 months of base salary.
Chief Executive Officer Compensation
Mr. Wallen received $200,000 in base salary for fiscal 2009. His annual base salary was not increased for fiscal year 2009. Mr. Wallen received no common stock awards during fiscal 2009.
Chief Financial Officer Compensation
Mr. Badgley’s salary has been established at $145,000 per year, plus a $300 per month health insurance subsidy. In the event that Mr. Badgley is terminated without cause, as determined by the Board of Directors of the Company, he will be entitled to three months salary. The Company and Mr. Badgley did not enter into a written employment agreement.
Summary Compensation Table
The following table shows information regarding the compensation earned during the fiscal years ended June 30, 2009, 2008 and 2007 by our Chief Executive Officer, our current Chief Financial Officer, our former Chief Financial Officer and our other most highly compensated executive officer who was employed by us as of June 30, 2009 and whose total compensation exceeded $100,000 during the most recent fiscal year (the “Named Executive Officers”):
(1)
This column represents the dollar amount recognized for financial statement reporting purposes with respect to the 2009 and 2008 fiscal years for the fair value of stock grants for each of the named executive officers in accordance with SFAS No. 123R. On January 31, 2008 we granted our Named Executive Officers a total of 250,000 unregistered shares of common stock as follows: Mr. Wallen, 150,000 shares; and Mr. Ross, 100,000 shares. These shares vested immediately on the grant date. On August 20, 2007, Mr. Guffey was granted 90,000 unregistered shares of common stock, which vested on a quarterly schedule. On January 10, 2007 we granted our Named Executive Officers a total of 272,500 unregistered shares of common stock as follows: Mr. Wallen, 150,000 shares; and Mr. Ross, 47,500 shares. These shares vested immediately on the grant date.
(2)
All Other Compensation consists solely of a $300 per month reimbursement towards each officer’s medical insurance premiums. The Company does not provide group health insurance coverage to its employees.
(3)
Mr. Badgley was appointed Cubic’s Chief Financial Officer effective October 13, 2008.
(4)
Mr. Guffey resigned as Cubic’s Chief Financial Officer effective October 3, 2008.
Fiscal 2009 Grants of Plan-Based Awards
No stock options were granted to executive officers last year and thus any reference to options has been omitted.
Stock Grants
On January 10 and January 18, 2007, the Company issued 489,500 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $391,600 and $42,000, respectively, based on the last sale price on the OTC Bulletin Board of the Company’s common stock. Such amounts were amortized to compensation expense on a quarterly basis during calendar year 2007. An additional $30,000 was recorded when our former Chief Financial Officer resigned during fiscal 2007. Accordingly, $186,800 and $246,800 was recorded as compensation expense and included in general and administrative expense for the fiscal years ended June 30, 2008 and 2007, respectively. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III and (ii) 47,500 unregistered shares to Jon S. Ross.
On August 20, 2007, the Company issued 90,000 unregistered shares to our former Chief Financial Officer pursuant to the Plan, with such grant subject to vesting in quarterly installments over the following four quarters. As of such date, the aggregate market value of the common stock granted was $103,500 based on the then market price on the OTCBB of the Company’s common stock. Such amount was amortized to compensation expense on a quarterly basis during fiscal years 2008 and 2009. Accordingly, $90,563 was recorded as compensation expense and included in general and administrative expenses for fiscal 2008. The remaining $12,937 was amortized to compensation expense in the first quarter of fiscal 2009, which ended September 30, 2008.
On January 31 and February 4, 2008, the Company issued 555,000 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $893,550 and $84,525 (a total of $978,075), respectively, based on the then-market price on the OTCBB of the Company’s common stock. Recent SEC guidance requires that immediately-vesting common stock grants with no forfeiture provisions be expensed at the time of grant rather than amortized over the four quarters of the service period. Accordingly, the full $978,075 was recorded as compensation expense and included in general and administrative expenses for the fiscal year ended June 30, 2008. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III, (ii) zero unregistered shares to Scott D. Guffey, and (iii) 100,000 unregistered shares to Jon S. Ross.
On January 12, 2009, the Company issued 235,000 unregistered shares to three directors of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $385,400 based on the last sale price ($1.64/share) on the aforementioned date, on the NYSE - Amex, of the Company’s common stock. Such amounts were expensed upon issuance to compensation expense.
On January 28, 2009, the Company authorized the issuance of 250,000 and 122,500 unregistered shares, respectively, to the officers and key employees of the Company pursuant to the Plan, which shares are subject to forfeiture in the event that such recipient’s service with the Company terminates prior to a specified date. These shares are authorized, but not issued as of September 25, 2009.
Outstanding Equity Awards at Fiscal Year-End
The Company had no outstanding stock options at June 30, 2009. The Company had no unvested stock awards at the end of fiscal 2009.
Option Exercises and Stock Vesting
No stock options were granted to executive officers during fiscal 2009 and thus any reference to options has been omitted.
Information Related to Stock-Based Compensation
The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This Statement requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation cost is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2006. See “Stock Grants”.
Non-Employee Director Compensation for Fiscal 2009
(1)
Represents the amount of cash compensation earned in fiscal 2009 for Board and Committee service. Each non-employee director was paid a stipend of $1,000 for each Board of Directors or Committee meeting attended (whether in person or via teleconference) beginning with the January 7, 2009 Board meeting, with various meetings occurring on the same date being provided one stipend.
(2)
Each non-employee director as of January 2009 received: 40,000 shares of common stock for service on the Board of Directors; 20,000 shares of common stock for service on the Audit Committee; and, 15,000 shares of common stock for service on the Compensation Committee. Mr. Howard received an additional 10,000 shares of common stock for serving as the financial expert and Chairman of the Audit Committee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth the number of shares of the Company’s common stock beneficially owned, as of September 1, 2009 by (i) each person known to the Company to beneficially own more than 5% of the common stock of the Company (the only class of voting securities now outstanding), (ii) each Director and Named Executive Officer, and (iii) all directors and executive officers as a group. Unless otherwise indicated, we consider all shares of common stock that can be issued under convertible securities or warrants currently or within 60 days of September 1, 2009 to be outstanding for the purpose of computing the percentage ownership of the person holding those securities, but do not consider those securities to be outstanding for computing the percentage ownership of any other person. Each owner’s percentage is calculated by dividing the number of shares beneficially held by that owner by the sum of 62,570,564 and the number of shares that owner has the right to acquire within 60 days.
* Denotes less than one percent
(1)
Based on a total of 62,570,564 shares of Common Stock issued and outstanding on September 1, 2009.
(2)
Includes warrants to purchase 2,500,000 shares and a promissory note convertible into 5,000,000 shares owned by Wells Fargo Energy Capital.
(3)
Includes 901,955 shares held jointly by Steven S. Bruggeman and Jacqueline Bruggeman as joint tenants with rights of survivorship; 65,250 shares held by Mr. Bruggeman’s spouse, of which Mr. Bruggeman disclaims beneficial ownership and, 2,228,500 shares and warrants to purchase 1,000,000 shares individually held by Steven S. Bruggeman.
(4)
Includes 614,862 shares and warrants to purchase 50,000 shares held by Tauren Exploration, Inc., an entity controlled by Mr. Wallen; 500,000 shares held by spouse; and, 430,000 shares held by minor children.
(5)
Includes 4138 shares conveyed to Diversified Dynamics from Mr. Wallen as part of an interest payment. 2,034,000 shares and warrants to purchase 600,000 shares held by Diversified Dynamics Corporation, a company controlled by Mr. Bruggeman; 304,000 shares owned by Mr. Bruggeman: 120,000 shares owned by Consumer Products Corp., in which Mr. Bruggeman’s spouse, Ruth, is a joint owner; and, 15,047,397 shares owned by Mr. and Mrs. Bruggeman, as joint tenants with rights of survivorship.
(6)
Includes 109,527 shares held with spouse as joint tenants with rights of survivorship; and, warrants to purchase 50,000 shares.
(7)
Includes 322,245 shares are held by Mr. Howard’s spouse, Belva, of which Mr. Howard disclaims beneficial ownership.
(8)
Includes 6,000 shares held by minor children.
(9)
Includes 390,287 shares held with spouse as joint tenants with rights of survivorship.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Certain Relationships and Related Transactions
On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation, an entity controlled by William L. Bruggeman, Jr. who, at the time of such transaction, was the beneficial owner of approximately 28.9% of the common stock of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. The Company is paying interest on the note on a monthly basis.
In addition, all but eight wells in which the Company owns a working interest are operated by an affiliated company, Fossil Operating, Inc. (“Fossil”), an entity wholly-owned by the Company’s President, Chief Executive Officer and Chairman of the Board, Calvin A. Wallen III. In consideration for Fossil serving as operator and to satisfy the Company’s working interest obligations related to drilling costs and lease operating expenses, Cubic paid to Fossil an aggregate of $4,244,397, $14,288,122 and $4,120,012 during fiscal 2009, 2008 and 2007, respectively; and Fossil paid Cubic an aggregate of $151,680, $310,407 and $384,659 during fiscal 2009, 2008 and 2007, respectively for oil and gas sales. As of June 30, 2009, 2008 and 2007, the Company owed Fossil $815,239, $862,895 and $1,659,786, respectively, for drilling costs and lease operating expenses, and was owed by Fossil $271,615, $450,669 and $28,446, respectively, for oil and gas sales. The Company and Fossil have operating agreements with respect to all wells for which Fossil serves as operator.
It is the Company’s policy that any transactions between us and related parties will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.
Director Independence
Messrs. Howard, Clements, Bayer and Bruggeman and Ms. Harding meet the independence standards for independent directors under the rules of the SEC and the rules of the NYSE Amex, LLC. Messrs. Howard, Clements and Bayer also meet the independence standards for independent directors applicable to serving on the Audit Committee, under the rules of the SEC and the rules of the NYSE Amex, LLC.
Item 14.
Item 14. Principal Accountant Fees and Services.
Audit Fees
Aggregate audit fees billed for professional services rendered by Philip Vogel & Co., PC were $35,500 for the year ended June 30, 2009 and $27,000 for the year ended June 30, 2008. Such fees were primarily for professional services rendered for the audits of our consolidated financial statements during the fiscal years ended June 30, 2009 and 2008.
Audit-Related Fees
Aggregate audit-related fees billed for professional services rendered by Philip Vogel & Co., PC were $12,300 for the year ended June 30, 2009 and $10,100 for the year ended June 30, 2008. Such fees were for limited reviews of our unaudited condensed consolidated interim financial statements.
Tax Fees
Aggregate income tax compliance and related services fees billed for professional services rendered by Philip Vogel & Co., PC were $5,000 for the year ended June 30, 2009 and $4,180 for the year ended June 30, 2008.
All Other Fees
In addition to the fees described above, aggregate fees of: $2,280 were billed by Philip Vogel & Co., PC during the year ended June 30, 2009, primarily for review of our Form S-3 registration statements and related amendments, attendance at our annual shareholders’ meeting; and $3,400 were billed by Philip Vogel & Co., PC during the year ended June 30, 2008, primarily for review of our Form SB-2 registration statements and related amendments, and attendance at our annual shareholders’ meeting, and for research regarding our compliance with Section 404 of the Sarbanes-Oxley Act of 2002.
Audit Committee Pre-Approval Policies and Procedures
In accordance with Company policy, any additional audit or non-audit services must be approved in advance. All of the foregoing professional services provided by Philip Vogel & Co., PC during the years ended June 30, 2009 and June 30, 2008 were pre-approved in accordance with the policies of our Audit Committee.
SIGNATURES
Pursuant to requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on September 28, 2009.
Pursuant to requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Calvin A. Wallen, III
Chairman, President and Chief Executive
September 28, 2009
Calvin A. Wallen, III
Officer (principal executive officer)
/s/ Larry G. Badgley
Chief Financial Officer
September 28, 2009
Larry G. Badgley
(principal financial and accounting officer)
/s/ Jon S. Ross
Secretary and Director
September 28, 2009
Jon S. Ross
/s/ Gene C. Howard
Director
September 28, 2009
Gene C. Howard
/s/ Herbert A. Bayer
Director
September 28, 2009
Herbert A. Bayer
/s/ Robert L. Clements
Director
September 28, 2009
Robert L. Clements
/s/ Phyllis K. Harding
Director
September 28, 2009
Phyllis K. Harding
/s/ William L. Bruggeman, Jr.
Director
September 28, 2009
William L. Bruggeman, Jr.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) (1) and (2) Financial Statements and Financial Statement Schedules
See “Index to Financial Statements” on page.
(a) (3) Exhibits
See the Exhibit Index immediately preceding the Exhibits filed with this report.
CUBIC ENERGY, INC.
JUNE 30, 2009
Page
Independent Auditors’ Report
Financial Statements:
Balance Sheets
Statements of Operations
Statements of Changes in Shareholders’ Equity
Statements of Cash Flows
Notes to Financial Statements
Note A - Background and general
Note B - Significant accounting policies
Note C - Shareholders’ equity
Note D - Loss per common share
Note E - Long-term debt
Note F - Related party transactions
Note G - Income taxes
Note H - Commitments and contingencies
Note I - Cost of oil and gas properties
Note J - Oil and gas reserves information (unaudited)
Note K - Selected quarterly financial data (unaudited)
Note L - Subsequent events
Note M - Going Concern
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Stockholders of Cubic Energy, Inc.,
We have audited the balance sheets of Cubic Energy, Inc., a Texas corporation, as of June 30, 2009 and 2008, and the related statements of operations, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended June 30, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 financial statements referred to above present fairly, in all material respects, the financial position of Cubic Energy, Inc. as of June 30, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended June 30, 2009, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note M to the financial statements, the Company has experienced recurring net losses from operations and has uncertainty regarding its ability to meet its loan obligations. These factors raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
PHILIP VOGEL & CO. PC
Certified Public Accountants
Dallas, Texas
September 25,
CUBIC ENERGY, INC.
BALANCE SHEETS
JUNE 30, 2009 AND 2008
The accompanying notes are an integral part of these statements.
CUBIC ENERGY, INC.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 2009, 2008, AND 2007
The accompanying notes are an integral part of these statements.
CUBIC ENERGY, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED JUNE 30, 2009, 2008, AND 2007
The accompanying notes are an integral part of these statements.
CUBIC ENERGY, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2009, 2008, AND 2007
The accompanying notes are an integral part of these statements.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note A - Background and general:
Cubic Energy, Inc. (the “Company”) is engaged in domestic crude oil, natural gas and natural gas liquids exploration, development and production, with primary emphasis on the production of oil and gas reserves through the acquisition and development of proved, producing oil and gas properties in the states of Texas and Louisiana.
Note B - Significant accounting policies:
Cash equivalents
For purposes of the statements of cash flows, the Company considers all certificates of deposit and other financial instruments with original maturity dates of three months or less to be cash equivalents.
Office and other equipment
Office and other equipment are stated at cost and depreciated by the straight-line method over estimated useful lives ranging from five to seven years. Depreciation and amortization of office and other equipment amounted to $5,193, $2,526 and $1,524 for the years ended June 30, 2009, 2008 and 2007, respectively.
Impairment of long-lived assets and long-lived assets to be disposed of
The Company has adopted the provisions of the Financial Accounting Standards Board’s (the “FASB”) Statement of Financial Accounting Standards (“FAS”) No. 144 (“FAS No. 144”), Accounting for the Impairment or Disposal of Long-Lived Assets effective for periods beginning July 1, 2002, and thereafter. FAS No. 144 replaces FAS No. 121, and, among other matters, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. FAS No. 144 retains the basic provisions of FAS No. 121, but broadens its scope and establishes a single model for long-lived assets to be disposed of by sale. In addition, the Company is subject to the rules of the Securities and Exchange Commission with respect to impairment of oil and gas properties accounted for under the full cost method of accounting, as described below.
Full cost method of accounting for oil and gas properties
The Company has adopted the full cost method of accounting for oil and gas properties. Management believes adoption of the full cost method more accurately reflects management’s exploration objectives and results by including all costs incurred as integral for the acquisition, discovery and development of whatever reserves ultimately result from its efforts as a whole. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs related to exploratory and development activities, and directly related overhead costs, are capitalized into the full cost pool.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
In addition, the capitalized costs are subject to a “full cost ceiling test,” which generally limits such costs to the aggregate of the “estimated present value” (discounted at a 10 percent (10%) interest rate) of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. Accordingly, an impairment of oil and gas properties charge of $20,390,819 was recorded in fiscal 2009, no impairment charge was recorded for 2008 and $1,790,882 was recorded for fiscal 2007.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
Depletion of producing oil and gas properties amounted to $766,668, $2,149,570 and $360,910 for the years ended June 30, 2009, 2008 and 2007, respectively.
Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates that will apply in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
In September 2005, the Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 05-08, Income Tax Consequences of Issuing Convertible Debt with a Beneficial Conversion Feature (“EITF 05-08”). Under EITF 05-08, the issuance of convertible debt with a beneficial conversion feature results in a temporary difference for purposes of applying FAS No. 109, Accounting for Income Taxes. The deferred taxes recognized for the temporary difference should be recorded as an adjustment to paid-in capital. EITF 98-05, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, and EITF 00-27, Application of Issue No. 98-05 to Certain Convertible Instruments, require that the non-detachable conversion feature of a convertible debt security be accounted for separately if it is a beneficial conversion feature. A beneficial conversion feature is recognized and measured by allocating to additional paid-in capital a portion of the proceeds equal to the conversion feature’s intrinsic value. A discount on the convertible debt is recognized for the amount that is allocated to additional paid-in capital. The debt discount is accreted from the date of issuance to the stated redemption date of the convertible instrument or through the earliest conversion date if the instrument does not have a stated redemption date. The U.S. Internal Revenue Code includes the entire amount of proceeds received at issuance as the tax basis of the convertible debt security. The adoption of EITF 05-08 has had no impact on the Company’s financial statements because none of the conversion features embedded in the Company’s notes payable is considered beneficial.
In July 2006, the FASB issued Interpretation No. 48 (“FIN No. 48”), Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109, which clarifies the accounting for uncertainty in tax positions. FIN No. 48 requires that the Company recognize in the financial statements the impact of a tax position if that position is more likely than not of being sustained upon audit, based on the technical merits of the position. FIN No. 48 became effective for fiscal years beginning after December 15, 2006. The adoption of FIN No. 48 has had no impact on the Company’s financial statements.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Oil and gas revenues
The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Differences between sales and production volumes during the years ended June 30, 2009, 2008 and 2007 were not significant.
Earnings (loss) per common share
The Company has adopted the provisions of FAS No. 128, Earnings per Share. FAS No. 128 requires the presentation of basic earnings (loss) per share (EPS) and diluted EPS. Basic EPS is calculated by dividing net income or loss (available to common stockholders) by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock, such as stock options, warrants, convertible preferred stock and convertible debentures, were exercised or converted into common stock.
As discussed in Note D, there were no dilutive securities outstanding during the years ended June 30, 2009, 2008 and 2007. The weighted average number of common and common equivalent shares outstanding was 61,150,400, 56,974,407 and 50,338,450 for the years ended June 30, 2009, 2008 and 2007, respectively.
Concentration of credit risk
Financial instruments which potentially subject the Company to a concentration of credit risk consist primarily of trade accounts receivable with a variety of local, national, and international oil and natural gas companies. Such credit risks are considered by management to be limited due to the financial resources of the oil and natural gas companies.
The Company had cash balances of approximately $73,242, at June 30, 2009, in one banking institution; such amount is not in excess of the federally insured amount of $250,000 for each institution. This balance is before considering outstanding items.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Reporting comprehensive income (loss) and operating segments
The Company has adopted the provisions of FAS No. 130, Reporting Comprehensive Income, and FAS No. 131, Disclosure about Segments of an Enterprise and Related Information. FAS No. 130 requires that an enterprise report, by major components and as a single total, the change in its net assets during the period from non-owner sources. FAS No. 131 establishes annual and interim reporting standards for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. Adoption of FAS No. 130 and FAS No. 131 has had no impact on the Company’s financial position, results of operations, cash flows, or related disclosures because the Company’s operations are considered to be a single segment.
Use of estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Certain significant estimates
Management’s estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimate. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.
Fair value of financial instruments
The Company defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. Financial instruments included in the Company’s financial statements include cash and cash equivalents, short-term investments, accounts receivable, other receivables, other assets, accounts payable, notes payable and due to affiliates. Unless otherwise disclosed in the notes to the financial statements, the carrying value of financial instruments is considered to approximate fair value due to the short maturity and characteristics of those instruments. The carrying value of debt approximates fair value as terms approximate those currently available for similar debt instruments.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Asset retirement obligations
The Company has adopted the provisions of FAS No. 143, Accounting for Asset Retirement Obligations, effective July 1, 2002. FAS No. 143 amended FAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and, among other matters, addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the related asset and allocated to expense over the asset’s useful life.
This is a change from the approach taken under FAS No. 19, whereby an amount for an asset retirement obligation was recognized using a cost-accumulation measurement approach. Under that approach, the obligation was reported as a contra-asset recognized as part of depletion and depreciation over the life of the asset without discounting. Management has determined that adopting FAS No. 143 has had no significant effect on the Company’s financial statements since abandonment costs for which it is responsible are not material.
In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN No. 47”), Accounting for Conditional Asset Retirement Obligations. FIN No. 47 clarifies that a conditional asset retirement obligation, as used in FAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing or method of the settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. FIN No. 47 became effective for fiscal years ending after December 15, 2005. The adoption of FIN No. 47 has had no impact on the financial statements of the Company.
Stock-based compensation
The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This FAS requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2006.
Prior to adopting FAS No. 123R, the Company applied APB No. 25 and related interpretations, which required that compensation expense be recorded on the date of the grant of stock options and warrants only if the current market price of the underlying stock exceeded the exercise price. Alternatively, FAS No. 123R permits entities to recognize, as expense over the vesting period, the fair value of all stock-based awards on the date of grant. No retroactive or cumulative effect adjustments were required upon the Company’s adoption of FAS No. 123R.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
In December 2002, the FASB issued FAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, which amends FAS No. 123. FAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based compensation. In addition, FAS No. 148 amends the disclosure requirements of FAS No. 123 to require more prominent and more frequent disclosures in financial statements about the effects of stock-based compensation. The transition guidance and annual disclosure provisions are effective for fiscal years ending after December 15, 2002. The interim disclosure provisions became effective for financial reports containing financial statements for interim periods beginning after December 15, 2002. The other requirements of this standard have been adopted by the Company for periods beginning January 1, 2003.
Additionally, in August 2005, the FASB issued FASB Staff Position (“FSP”) No. 123R-1 (“FSP1”), Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R). In FSP1, the FASB decided to defer the requirements in FAS No. 123 that make a freestanding financial instrument subject to the recognition and measurement requirements of other GAAP when the rights conveyed by the instrument are no longer dependent on the holder being an employee. In October 2005, the FASB issued FSP No. 123R-2 (“FSP2”), Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R). In FSP2, the FASB is providing companies with a “practical accommodation” when determining the grant date of an award that is subject to the accounting provisions in FAS No. 123R. In November 2005, the FASB issued FSP No. 123R-3 (“FSP3”), Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards. FSP3 provides an elective alternative method that establishes a computational component to arrive at the beginning balance of the accumulated paid-in capital pool related to employee compensation and a simplified method to determine the subsequent impact on the accumulated paid-in capital pool of employee awards that are fully vested and outstanding upon the adoption of FAS No. 123R.
In February 2006, the FASB issued FSP No. 123R-4 (“FSP4”), Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event, which concludes that a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not become a liability until it becomes probable that the event will occur. An option or similar instrument that is classified as equity, but subsequently becomes a liability because the contingent cash settlement event is probable of occurring, shall be accounted for similar to modification from an equity to liability award. To the extent that the liability exceeds the amount previously recognized in equity, the excess is recognized as compensation cost. The total recognized compensation cost for an award with a contingent cash settlement feature shall at least equal the fair value of the award at the grant date. FSP4 is applicable only for options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP1, FSP2, FSP3 and FSP4 has been applied concurrent with our adoption of FAS No. 123R.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
In March 2005, the SEC published Staff Accounting Bulletin No. 107 (“SAB No. 107”). The interpretations in this staff accounting bulletin express the views of the staff regarding the interaction between FAS No. 123R and certain SEC rules and regulations and provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. In particular, SAB No. 107 provides guidance related to share-based payment transactions with non-employees, the transition from non-public to public entity status, valuation methods (including assumptions such as expected volatility and expected term), the accounting for certain redeemable financial instruments issued under share-based payment arrangements, the classification of compensation expense, non-GAAP financial measures, first-time adoption of FAS No. 123R in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects of share-based payment arrangements upon adoption of FAS No. 123R, the modification of employee share options prior to adoption of FAS No. 123R and disclosures in Management’s Discussion and Analysis subsequent to adoption of FAS No. 123R. The provisions of SAB No. 107 became effective with our adoption of FAS No. 123R.
Exit or disposal activities
In July 2002, the FASB issued FAS No. 146, Accounting for Cost Associated with Exit or Disposal Activities. FAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operations, or other exit or disposal activities. FAS No. 146 is effective prospectively for exit or disposal activities initiated after December 31, 2002. No exit or disposal activities have been entered into by the Company.
Financial instruments with characteristics of both liabilities and equity
In May 2003, the FASB issued FAS No. 150 (“FAS No. 150”), Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. FAS No. 150 established standards for how a company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that a company classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) if certain criteria are met. Freestanding financial instruments that obligate the issuer to redeem the holder’s shares, or are indexed to such an obligation, and are settled in cash or settled with shares meeting certain conditions would be treated as liabilities. Many of those instruments were previously classified as equity.
In June 2005, the FASB issued FSP FAS No. 150-5 (“FAS No. 150-5”), Issuers Accounting under FASB Statement No. 150 for Freestanding Warrants and Other Similar Instruments on Shares that are Redeemable. FAS No. 150-5 clarifies that freestanding warrants and similar instruments on shares that are redeemable should be accounted for as liabilities under FAS No. 150 regardless of the timing of the redemption feature or price, even though the underlying shares may be classified as equity. FAS No. 150-5 became effective for the first reporting period beginning after June 30, 2006. Although the Company had outstanding warrants as of June 30, 2009, the shares issued upon exercise of the warrants are not redeemable; consequently, adoption of FAS No. 150-5 has not had an impact on the Company’s financial position, results of operations or cash flows.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Guarantee of debt
In November 2002, the FASB issued Interpretation No. 45 (“FIN No. 45”), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34. FIN No. 45 clarifies the requirements of FAS No. 5, relating to the guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees. This Interpretation clarifies that a guarantor is required to recognize, at the inception of certain types of guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee, and requires additional disclosures on existing guarantees even if the likelihood of future liability under the guarantees is deemed remote. The Company has not issued any guarantees and, therefore, the adoption of FIN No. 45 has not had a any impact on the Company’s financial statements.
Variable interest entities
In January 2003, the FASB issued Interpretation No. 46 (“FIN No. 46”), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. FIN No. 46 states that if a business enterprise has a controlling financial interest in a variable interest entity as the primary beneficiary, the assets, liabilities and results of the activities of the variable interest entity should be included in the consolidated financial statements of the business enterprise. This Interpretation explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. The primary beneficiary of a variable interest entity would be required to consolidate if the other equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN No. 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. The Company has no current contractual relationships or other business relationships with variable interest entities.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Accounting changes and error corrections
In May 2005, the FASB issued FAS No. 154 (“FAS No. 154”), Accounting Changes and Error Corrections - A Replacement of APB Opinion No. 20 and FASB Statement No. 3. FAS No. 154 replaces APB Opinion No. 20 (“APB No. 20”), Accounting Changes, and FAS No. 3 (“FAS No. 3”), Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for, and reporting of, a change in accounting principles. FAS No. 154 applies to all voluntary changes in accounting principles and changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Under previous guidance, changes in accounting principle were recognized as a cumulative effect in the net income of the period of the change. FAS No. 154 requires retrospective application of changes in accounting principle, limited to the direct effects of the change, to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change in accounting principle.
Additionally, FAS No. 154 requires that a change in depreciation, amortization or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle and that correction of errors in previously issued financial statements should be termed a “restatement.” The provisions in FAS No. 154 became effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of FAS No. 154 did not have a material impact on the Company’s financial position, results of operations or cash flows.
Debt modifications
In September 2005, the EITF reached a consensus on Issue No. 05-07 (“EITF No. 05-07”), Accounting for Modifications to Conversion Options Embedded in Debt Instruments and Related Issues. EITF No. 05-07 requires that a change in the fair value of a conversion option brought about by modifying the debt agreement be included in analyzing in accordance with EITF consensus on Issue No. 96-19 (“EITF No. 96-19”), Debtor’s Accounting for a Modification or Exchange of Debt Instruments, whether a debt instrument is considered extinguished. Under EITF No. 96-19’s requirements, an issuer who modifies a debt instrument must compare the present value of the original debt instrument’s cash flows to the present value of the cash flows of the modified debt. If the present value of those cash flows varies by more than 10 percent (10%), the modification is considered significant and extinguishments accounting is applied to the original debt. If the change in the present value of the cash flows is less than 10 percent (10%), the debt is considered to be modified and is subject to EITF No. 96-19’s modification accounting. EITF No. 05-07 requires that in applying the 10 percent (10%) test the change in the fair value of the conversion option be treated in the same manner as a current period cash flow. EITF No. 05-07 also requires that, if a modification does not result in an extinguishment, the change in fair value of the conversion option be accounted for as an adjustment to interest expense over the remaining term of the debt. The issuer should not recognize a beneficial conversion feature or reassess an existing beneficial conversion feature upon modification of the conversion option of a debt instrument that does not result in an extinguishment. EITF No. 05-07 became effective for modifications of debt instruments beginning in the first interim or annual reporting period beginning after December 15, 2005. The adoption of EITF No. 05-07 did not have a material impact on the Company’s financial position, results of operations or cash flows.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Certain hybrid financial instruments
In February 2006, the FASB issued FAS No. 155 (“FAS No. 155”), Accounting for Certain Hybrid Financial Instruments, which amends FAS No. 133 (“FAS No. 133”), Accounting for Derivative Instruments and Hedging Activities and FAS No. 140 (“FAS No. 140”), Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and improves the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. Specifically, FAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis. FAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of FAS No. 155 did not have a material impact on the Company’s financial position, results of operations or cash flows.
Reporting taxes collected
In March 2006, the EITF reached a tentative consensus on Issue No. 06-03 (“EITF No. 06-03”), How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF No. 06-03 addresses income statement classification and disclosure requirements of externally-imposed taxes on revenue-producing transactions. EITF No. 06-03 is effective for periods beginning after December 15, 2006. The adoption of EITF No. 06-03 did not have a material impact on the Company’s financial position, results of operations or cash flows.
Subsequent Events
In May 2009, the FASB issued SFAS No. 165 “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 sets forth (1) The period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) The circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) The disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009. The adoption of this statement did not have a material effect on the Company’s financial statements.
Other recent accounting pronouncements
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 was issued to address diversity in practice in quantifying financial statement misstatements. Current practice allows for the evaluation of materiality on the basis of either (1) the error quantified as the amount by which the current year income statement was misstated (“rollover method”) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (“iron curtain method”). The guidance provided in SAB No. 108 requires both methods to be used in evaluating materiality (“dual approach”). SAB No. 108 permits companies to initially apply its provisions either by (1) restating prior financial statements as if the dual approach had always been used or (2) recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
earnings. The adoption of SAB No. 108 did not have a material impact on the Company’s financial position, results of operations or cash flows.
In September 2006, the FASB issued FAS No. 157 (“FAS No. 157”), Fair Value Measurements. FAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FAS No. 157 does not require any new fair value measurements in financial statements, but standardizes its definition and guidance in GAAP. Thus, for some entities, the application of this statement may change current practice. FAS No. 157 was effective for us beginning on January 1, 2008. The adoption of FAS No. 157 did not have a material impact on the Company’s financial position, results of operations or cash flows.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
In February 2007, the FASB issued Statement of FAS No. 159 (“FAS No. 159”), The Fair Value Option for Financial Assets and Financial Liabilities. FAS No. 159 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. FAS No. 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. FAS No. 159 is effective for fiscal years beginning after November 15, 2007. Management is still currently evaluating the effect of this pronouncement on its financial statements.
In December 2007, the FASB issued FAS No. 141 (revised 2007) (“FAS No. 141(R)”), Business Combinations. FAS No. 141(R) provides companies with principles and requirements on how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, liabilities assumed, and any non-controlling interest in the acquiree as well as the recognition and measurement of goodwill acquired or a gain from a bargain purchase in a business combination. FAS No. 141(R) also requires certain disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. Acquisition costs associated with the business combination will generally be expensed as incurred. In addition, changes in an acquired entity’s valuation allowance for deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. FAS No. 141(R) is effective for business combinations occurring in fiscal years beginning after December 15, 2008. We have not yet assessed the impact FAS No. 141(R) will have if we engage in future business combinations.
In December 2007, the FASB issued FAS No. 160 (“FAS No. 160), Non-controlling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, which mandates that a non-controlling (minority) interest shall be reported in the consolidated statement of financial position within equity, separately from the parent company’s equity. This statement amends ARB No. 51 and clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity. FAS No. 160 also requires consolidated net income to include amounts to both parent and non-controlling interest and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. FAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008. We currently do not have any minority interests that would be subject to FAS No. 160, and we do not expect it to be material to our consolidated financial statements for fiscal 2009. Adoption of FAS No. 160 became effective January 1, 2009.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note C - Stockholders’ equity:
The Company’s authorized capital is 100,000,000 shares of $0.05 par value common stock and 10,000,000 shares of $0.01 par value preferred stock. No shares of preferred stock were issued or outstanding at June 30, 2009 and 2008. None of the above-referenced warrants had been exercised and all remained outstanding at June 30, 2009.
Stock and warrants
On December 16, 2005, the Company entered into a Securities Purchase Agreement and issued 2,500,000 common shares at a price of $0.80 per share and issued warrants, with five year expirations, for the purchase of up to 1,000,000 shares of Company common stock at an exercise price of $1.00 per share. The proceeds of the offering were used for exploratory drilling and working capital. 897,500 of the above-referenced warrants had been exercised and 102,500 remained outstanding at June 30, 2009.
On February 6, 2006, Cubic entered into a Credit Agreement with Petro Capital V, L.P. (“Petro Capital”) pursuant to which Petro Capital advanced to the Company $5,500,000. In connection with the funding under the Credit Agreement, the Company issued to Petro Capital and Petro Capital Securities, LLC, warrants, with five-year expirations, for the purchase of up to 1,833,334 and 250,000 shares, respectively, of Company common stock at an exercise price of $1.00 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to all such warrants still outstanding is currently $0.9651 per share. 1,550,000 of the above-referenced warrants issued to Petro Capital had been exercised and 283,334 remained outstanding at June 30, 2009. None of the 250,000 warrants issued to Petro Capital Securities, LLC had been exercised and all remained outstanding at June 30, 2009. The Company allocated the proceeds from the issuance of the senior debt to the warrants and the senior debt based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,203,752 was recorded as an increase in additional paid-in capital.
On July 28, 2006, Cubic entered into and consummated transactions pursuant to Subscription and Registration Rights Agreements (the “July 2006 Subscription Agreements”) with certain investors that are unaffiliated with the Company (the “Investors”). Pursuant to the Subscription Agreements, the Investors paid aggregate consideration of $2,100,000 to the Company for 3,000,000 shares of the Company’s common stock and warrants exercisable, through July 31, 2011, into 1,500,000 shares of common stock at $0.70 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to all such warrants is currently $0.6849 per share. 1,125,000 of the above-referenced warrants had been exercised and 375,000 remain outstanding at June 30, 2009.
On November 10, 2006, in connection with the extension of a promissory note, the Company issued to Tauren warrants, with three-year expirations, for the purchase of up to 50,000 shares of Company common stock at an exercise price of $0.70 per share.
On December 15, 2006, the Company entered into Subscription and Registration Rights Agreements (the “December 2006 Subscription Agreements”) with certain investors. One of the investors, William Bruggeman (and entities affiliated with him) was the beneficial owner, prior to this transaction, of approximately 23.0% of the common stock of the Company. In this transaction, Mr. Bruggeman (and entities affiliated with him) purchased an aggregate of 4,288,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $2,144,000. Mr. Bruggeman (and entities affiliated with him) received warrants to purchase 2,144,000 shares of common stock with an exercise price of $0.70 per share. Another investor, Bob Clements, a director of the Company, purchased 100,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $50,000. Mr. Clements received warrants to purchase 50,000 shares of common stock with an exercise price of $0.70 per share. Pursuant to the December 2006 Subscription Agreements, the investors paid aggregate consideration of $3,940,000 to the Company for 7,880,000 shares of the Company’s common stock and warrants exercisable into 3,940,000 shares of common stock. The warrants are exercisable through November 30, 2011, at $0.6963 per share. 2,240,000 of the above-referenced warrants have been exercised and 1,700,000 remained outstanding at June 30, 2009.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital (“Wells Fargo”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). In connection with entering into the Credit Facility, the Company issued to Wells Fargo warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company common stock at an exercise price of $.9911 per share. The term loan is also convertible into 5,044,900 shares of Company common stock at a conversion price of $.9911 per share. None of the above-referenced warrants had been exercised and all remained outstanding at June 30, 2008. The Company allocated the proceeds from the issuance of the debt to the warrants, the debt and net profits interest (see “Note E - Long-term debt”) based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,314,289 was recorded as an increase in additional paid-in capital and the value assigned to the net profits interest of $213,148 was recorded as a credit to the full cost pool for oil and gas properties.
During the fiscal year ended June 30, 2008, the Company received an aggregate total of $1,110,295 relating to the exercise of 2,730,000 warrants representing 2,314,665 shares of common stock.
Through the following exercises of warrants, we issued an aggregate of 3,482,500 shares of common stock, which were not registered under the Securities Act of 1933, as amended, during fiscal 2009.
On July 3, 2008, two warrant holders of the Company exercised warrants for an aggregate of 1,127,500 shares of Company common stock, through the payment of $777,002 to the Company.
On July 7, 2008, one warrant holder of the Company exercised warrants for 250,000 shares of Company common stock, through the payment of $243,950 to the Company.
On July 8, 2008, one warrant holder of the Company exercised warrants for 100,000 shares of Company common stock, through the payment of $70,000 to the Company.
On July 17, 2008, one warrant holder of the Company exercised warrants for 5,000 shares of Company common stock, through the payment of $5,000 to the Company.
On February 23, 2009, twenty-two warrant holders of the Company exercised warrants for 2,000,000 shares of Company common stock, through the payment of $1,400,000 to the Company. Included among these warrant holders were the following 5% beneficial owners: William L. Bruggeman, Jr. and Ruth J. Bruggeman JWROS exercised warrants for 1,544,000 shares and Steven S. Bruggeman exercised warrants for 24,000 shares.
Aggregate proceeds to the Company of the aforementioned stock issuances were $2,495,952, all of which have been or is expected to be used for working capital purposes. The aforementioned issuances were made in reliance upon an exemption from registration set forth in Section 4(2) of the Securities Act of 1993, as amended, which exempts transactions by an issuer not involving a public offering.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Stock-based compensation
On December 29, 2005, the shareholders of the Company approved the 2005 Stock Option Plan (the “Plan”) and 3,750,000 shares of common stock were reserved, of which 2,643,500 shares had been issued through June 30, 2009.
On January 10 and January 18, 2007, the Company issued 489,500 and 52,500 unregistered shares, respectively, to the officers, directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $391,600 and $42,000, respectively, based on the last sale price on the OTCBB of the Company’s common stock. Such amounts were amortized to compensation expense on a quarterly basis during calendar year 2007. An additional $30,000 was recorded when our former Chief Financial Officer resigned during fiscal 2007. Accordingly, $186,800 and $246,800 was recorded as compensation expense and included in general and administrative expense for the fiscal years ended June 30, 2008 and 2007, respectively. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III, (ii) 75,000 unregistered shares to James L. Busby, and (iii) 47,500 unregistered shares to Jon S. Ross.
On August 20, 2007, the Company issued 90,000 unregistered shares to the current Chief Financial Officer of the Company pursuant to the Plan, with such grant subject to vesting in quarterly installments over the following four quarters. As of such date, the aggregate market value of the common stock granted was $103,500 based on the then market price on the OTCBB of the Company’s common stock. Such amount is being amortized to compensation expense on a quarterly basis during fiscal years 2008 and 2009. Accordingly, $90,563 was recorded as compensation expense and included in general and administrative expenses for fiscal 2008. The remaining $12,938 was amortized to compensation expense in the first quarter of fiscal 2009, which ends September 30, 2008.
On January 31 and February 4, 2008, the Company issued 555,000 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $893,550 and $84,525, respectively (a total of $978,075), based on the then-market price on the OTCBB of the Company’s common stock. Recent SEC guidance requires that immediately-vesting common stock grants with no forfeiture provisions be expensed at the time of grant rather than amortized over four quarters. Accordingly, the full $978,075 was recorded as compensation expense and included in general and administrative expenses for the fiscal year ended June 30, 2008.
On January 12, 2009, the Company issued 235,000 unregistered shares to three directors of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $385,400 based on the last sale price ($1.64/share) on the aforementioned date, on the NYSE - Amex of the Company’s common stock. Such amounts were expensed upon issuance to compensation expense.
On January 28, 2009, the Company authorized the issuance of 250,000 and 122,500 unregistered shares, respectively, to the officers and key employees of the Company pursuant to the Plan, which shares are subject to forfeiture in the event that such recipient’s service with the Company terminates prior to a specified date. These shares are authorized, but not issued as of September 25, 2009.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
The following table provides information related to stock-based compensation for the years ended June 30, 2009, 2008 and 2007:
Note D - Loss per common share:
Potential dilutive securities (e.g., stock warrants and convertible debt) have not been considered because the Company reported a net loss and, accordingly, their effects would be anti-dilutive.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note E - Long-term debt:
February 2006 debt issue
On February 6, 2006, Cubic entered into a Credit Agreement with Petro Capital V, L.P. (“Petro Capital”) pursuant to which Petro Capital advanced to the Company $5,500,000. The indebtedness bore interest at a rate of 12.5% per annum, was scheduled to mature on February 6, 2009, and was secured by substantially all of the assets of the Company. $1,800,000 of the funded amount was used to retire the 7% Senior Secured Convertible Debentures that were due September 30, 2009, described above. In connection with the funding under the Credit Agreement, the Company issued to Petro Capital and Petro Capital Securities, LLC, warrants, with five-year expirations, for the purchase of up to 1,833,334 and 250,000 shares, respectively, of Company common stock at an exercise price of $1.00 per share.
The Company allocated the proceeds from the issuance of the senior debt to the warrants and the senior debt based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,203,752 was recorded as an increase in additional paid-in capital. The assignment of a value to the warrants resulted in a loan discount being recorded. The discount was being amortized over the original three-year term of the senior debt as additional interest expense. Amortization for the year ended June 30, 2007 was $298,371 and for the year ended June 30, 2006 was $174,451.
Cubic incurred loan costs of $483,643 on the issuance of the senior debt and warrants. The amount allocable to the senior debt of $367,586 was capitalized and was being amortized over the term of the senior debt. Amortization of loan costs for the senior debt was $83,101 for the year ended June 30, 2007 and was $48,587 for the year ended June 30, 2006.
The senior debt was retired on March 5, 2007, with proceeds from a new senior debt issue, as set forth below. In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(1,082,887). Such amount includes the write-off of deferred loan costs, ($235,898), and the write-off of the remaining loan discount, ($846,989).
March 2007 debt issue
On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital, Inc. (“Wells Fargo”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). The indebtedness bears interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, matures on March 1, 2010, and is secured by substantially all of the assets of the Company. Approximately $5,000,000 of the funded amount was used, together with cash on hand, to retire the Company’s aforementioned previously outstanding senior debt that was due February 6, 2009.
The revolving credit facility is subject to a borrowing base, initially set at $4,000,000, and is subject to periodic review. The convertible term loan of $5,000,000 is convertible into 5,000,000 shares of Cubic common stock at a conversion price of $1.00 per share.
In connection with entering into the Credit Facility, the Company issued to Wells Fargo warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company common stock at an exercise price of $1.00 per share.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
The Company allocated the proceeds from the issuance of the debt to the warrants, the debt and net profits interest (see below) based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,314,289 was recorded as an increase in additional paid-in capital and the value assigned to the net profits interest of $213,148 was recorded as a credit to the full cost pool for oil and gas properties. The assignment of a value to the warrants and net profits interest resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense. Amortization for the years ended June 30, 2009, 2008 and 2007 was 514,620, $516,030 and $164,961, respectively. Amortization for the fiscal year ending June 30, 2010 is expected to be approximately $342,610.
Cubic incurred loan costs of $240,613 on the issuance of the debt and warrants. The amount allocable to the debt of $166,590 has been capitalized and is being amortized over the term of the debt. Amortization for the years ended June 30, 2009, 2008 and 2007 was $55,733, $55,886 and $17,865, respectively. Amortization for the fiscal year ending June 30, 2010 is expected to be approximately $37,105. Cubic incurred commitment fees of $170,000 related to subsequent increases in the Credit Facility’s borrowing base; such amount was capitalized in fiscal 2008 and is being amortized over the remaining term of the loan. Amortization for the year ended June 30, 2009 and 2008 was $79,001 and $38,404, respectively. Amortization for the fiscal year ending 2010 is expected to be approximately and $52,595.
May 2008 subordinated debt issue
On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 (the “Subordinated Note”) to Diversified Dynamics Corporation (the “Lender”), an entity controlled by William Bruggeman, who beneficially owns more than 5% of the common stock of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. As consideration for the loan made by Lender pursuant to the Subordinated Note, the Company agreed to convey to Lender, upon the repayment in full of the indebtedness evidenced by the Subordinated Note and the repayment in full of the senior indebtedness evidenced by the Credit Facility with Wells Fargo, an undivided 0.375% net profits interest in the future production of hydrocarbons from or attributable to Cubic’s net interest in its Louisiana properties. The proceeds of the Subordinated Note are being used for general corporate and working capital purposes.
Issuing the Subordinated Note required the consent of the holder of the Company’s senior indebtedness, Wells Fargo, which consent it granted on May 5, 2008. Subsequently, on May 8, 2008, the Credit Facility with Wells Fargo was amended by the First Amendment to the Credit Agreement (the “First Amendment”). Material provisions of the First Amendment included the following: (i) the Company may not prepay all or any part of the principal balance outstanding on the Term Loan prior to its maturity on March 1, 2010; and (ii) the amount of the Borrowing Base was decreased to $7,500,000, which amount was fully drawn upon, at the end of fiscal 2009.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note F - Related party transactions:
Effective January 1, 2002, the Company entered into an agreement with Tauren Exploration, Inc., an entity controlled by Cubic’s Chairman of the Board, President and CEO (“Tauren”) that provides for the following:
1) As of January 1, 2002, the Company owed Tauren $856,712, primarily comprised of non-interest bearing advances the Company had received over the course of several years. In exchange for the amounts owed to it, Tauren accepted the transfer of 856,712 newly issued and unregistered shares of common stock in the Company that had a market price of $0.70 per share.
2) The Company received the rights to participate in prospective oil and gas projects in which Tauren owns a working interest.
3) The Company shall, as requested, have the future privilege of using the general and administrative services of Tauren based on an agreed pro rata cost.
4) The Company issued three series of warrants to Tauren as described in Note C.
On December 1, 1997, as renewed and revised on January 1, 2002, the Company entered into a contract with Tauren to provide the necessary technical, administrative and management expertise needed to conduct its business. Tauren also paid various organization costs and consulting fees on behalf of the Company. The monthly amount charged to the Company was based on actual costs of materials and labor hours of Tauren that were used pursuant to the terms of the agreement. The agreement was terminated effective January 1, 2006, except as to the office sharing provisions, which were extended to June 30, 2007 and since continue on a month to month basis. The Company now has 10 employees and its offices are subleased from Tauren. During fiscal 2008, the Company’s only expense under the office sharing arrangement was the rent sublease. Charges to the Company under the contracts and subsequent arrangements were $26,748, $26,748 and $29,285 for the years ended June 30, 2009, 2008 and 2007, respectively.
Tauren owns a working interest in the wells in which the Company owns a working interest. As of June 30, 2009, the Company owes $649,205 to Tauren for miscellaneous general and administrative expenses and lease operating expenses paid by Tauren on the Company; as of June 30, 2008, the Company owed Tauren $942 for miscellaneous general and administrative expenses paid by Tauren on the Company’s behalf; and, as of June 30, 2007, the Company owed Tauren $3,715, for miscellaneous general and administrative expenses paid by the Company on Tauren’s behalf.
In addition, all but three wells in which the Company owns a working interest are operated by an affiliated company, Fossil Operating, Inc. (“Fossil”), which is owned 100% by the Company’s President and Chief Executive Officer, Calvin A. Wallen III. As of June 30, 2009, 2008 and 2007, the Company owed Fossil $815,239, $862,895, and $1,659,786, respectively, for drilling costs and lease and operating expenses, and was owed by Fossil $271,615, $450,669, and $28,446, respectively, for oil and gas sales.
On February 6, 2006, the Company entered into a Purchase Agreement with Tauren with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
to acquire at “cost” (as defined in the Purchase Agreement) a seventy percent (70%) working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 unregistered shares of Company common stock, (c) an unsecured 12.5% promissory note in the amount of $1,300,000, which note was convertible into Company common stock at a conversion price of $0.80 per share (the “Tauren Note”), and (d) a drilling credit of $2,100,000. Total interest paid to Tauren under terms of the Tauren Note was$0 in fiscal 2009, $0 in fiscal 2008 and $96,610 in fiscal 2007.
The consideration described above was determined based upon negotiations between Tauren and a Special Committee of the Company’s directors, excluding Mr. Wallen. The Special Committee obtained an opinion from its independent financial advisor with respect to the fairness, from a financial point of view, to the public stockholders of the Company, of such transactions.
On November 10, 2006, the maturity of the Tauren Note was extended to October 5, 2007. In connection with the extension of the Tauren Note, the Company issued to Tauren warrants, with three-year expirations, for the purchase of up to 50,000 shares of Company common stock at an exercise price of $0.70 per share.
On February 2, 2007, the Tauren Note was retired pursuant to a provision in the note that required payment from the proceeds of an equity offering. The equity offering that occurred in December 2006 (see “Note C - Stockholders’ Equity”) was sufficient to facilitate such repayment.
On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation, an entity controlled by William Bruggeman who, at the time of such transaction, was the beneficial owner of approximately 28.9% of the common stock of the Company. See “May 2008 subordinated debt issue” in “Note E - Long-term debt” elsewhere herein.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note G - Income taxes:
Deferred tax assets and liabilities are computed by applying the effective U.S. federal income tax rate to the gross amounts of temporary differences and other tax attributes. Deferred tax assets and liabilities relating to state income taxes are not material. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. As of June 30, 2009, 2008 and 2007, the Company believed it was more likely than not that future tax benefits from net operating loss carryforwards and other deferred tax assets would not be realizable through generation of future taxable income; therefore, they were fully reserved.
The components of the net deferred federal income tax assets (liabilities) at June 30 were as follows:
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
The following table summarizes the difference between the actual tax provision and the amounts obtained by applying the statutory tax rates to the income or loss before income taxes for the years ended June 30, 2009, 2008 and 2007:
As of June 30, 2009, the Company had net operating loss carryforwards of approximately $42,317,519, which are available to reduce future taxable income. These carryforwards expire as follows:
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note H - Commitments and contingencies:
Key personnel
The Company depends to a large extent on the services of Calvin A. Wallen III, the Company’s President, Chairman of the Board, and Chief Executive Officer. The loss of the services of Mr. Wallen would have a material adverse effect on the Company’s operations.
On February 29, 2008, the Company entered into employment agreements with its President and Chief Executive Officer, Calvin A. Wallen, III, and Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.
Both agreements provide for a term of employment of 36 months from the effective date of February 1, 2008, which term shall be automatically extended by one additional month upon the expiration of each month during the term; provided, that the Company may terminate subsequent one-month extensions at any time. Each agreement is subject to early termination by the Company in the event that the employee dies, becomes totally disabled or commits an act constituting “Just Cause” under the agreement. The agreements provide that Just Cause includes, among other things, the conviction of certain crimes, habitual neglect of his duties to the Company or other material breaches by the employee of the agreement. Each agreement also provides that the employee shall be permitted to terminate his employment upon the occurrence of “Good Reason,” as defined in the agreement. The agreements provide that Good Reason includes, among other things, a material diminution in the employee’s authority, duties, responsibilities or salary, or the relocation of the Company’s principal offices by more than 50 miles. If the employee’s employment is terminated by (a) the Company other than due to the employee’s death, disability or Just Cause, or (b) the employee for Good Reason, then the Company is required to pay all remaining salary through the end of the then-current term. The foregoing severance payment is subject to reduction under certain conditions.
Environmental matters
The Company’s operations and properties are subject to extensive and changing federal, state, provincial and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment. The Company generates typical oil and gas field wastes, including hazardous wastes that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. Furthermore, certain wastes generated by the Company’s oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly operating and disposal requirements. All of the Company’s properties are operated by third parties over whom the Company has limited control. In addition to the Company’s lack of control over properties operated by others, the failure of previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note I - Cost of oil and gas properties:
Costs incurred
Costs (capitalized and expensed) incurred in oil and gas property acquisition, exploration, and development activities for the years ended June 30, 2009, 2008 and 2007 were as follows:
Capitalized costs
The aggregate amounts of capitalized costs relating to oil and gas producing activities and the aggregate amounts of the related accumulated depreciation, depletion, and amortization at June 30, 2009, 2008 and 2007 were as follows:
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Results of operations
The results of operations from oil and gas producing activities for the years ended June 30, 2009, 2008 and 2007 were as follows:
Note J - Oil and gas reserves information (unaudited):
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations over prices and costs existing at year-end except by contractual arrangements.
The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company’s policy is to amortize capitalized oil and gas costs on the unit of production method, based upon these reserve estimates. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties, or any combination of the above may be increased or reduced in the near term.
If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
The following unaudited table sets forth proved oil and gas reserves, all within the United States, at June 30, 2009, 2008 and 2007 together with the changes therein:
The majority of the Company’s Louisiana acreage lies atop the center of what is known in our industry as the “Haynesville Shale Play” (which we refer to as the “Bossier/Haynesville shale” elsewhere herein), one of the most prolific field discoveries in the United States. The discovery of the existence of the Bossier/Haynesville shale formations in the Company’s acreage in fiscal 2008 mandated a redirection in capital away from a strategy of maximizing the development of the Cotton Valley and other shallow formations in our Bethany Longstreet and Johnson Branch fields, and to the strategy of acquiring and retaining as much Bossier/Haynesville shale acreage as possible. This necessitated more cost efficient completion techniques on wells drilled and did and does impair our production. It is in the Company’s future development plans to re-complete many of our producing wells at a later date, as Cotton Valley wells completed in late fiscal 2008 and early fiscal 2009 with more extensive completion techniques showed and still show much greater levels of production.
Fiscal 2009 was a period of limited field activity by the Company. Deteriorating economic conditions, the harsh debt and equity environment, stubbornly high field operation costs, and collapse in the pricing of natural gas as a commodity forced the Company to conserve cash. Field activity was limited as to what was necessary to preserve the asset base of the Company. Production volumes from Company wells decreased and only four new wells were brought online in fiscal 2009. The goal of the Company evolved into positioning itself in the best way possible to take advantage of the time when natural gas pricing and general economic conditions became more favorable.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
The “Revisions of previous estimates” amount of 5,233,858 Mcf in fiscal 2009
The “Extensions and discoveries” amount of 9,275,556 Mcf in fiscal 2009
The “Revisions of previous estimates” amount of 5,233,858 Mcf in fiscal 2009 was primarily a result of more performance information being available for the fiscal 2009 reserve report. Based on updated performance rates and significantly lower natural gas prices, downward revisions of an aggregate of 979,273 Mcf were made to the Proved Developed reserves of the 22 Cotton Valley vertical wells. Despite depressed natural gas prices, an upward revision of an aggregate of 5,933,615 Mcf was recognized for certain Sections in which the Company maintains a working interest stemming from pre-existing PUD offset locations, resulting from the proximity to a competitor’s productive horizontally-drilled Haynesville Shale wells.
The “Extensions and discoveries” amount of 9,275,556 Mcf in fiscal 2009 was primarily due to new PUD offset locations in which the Company maintains a working interest based upon the proximity to a competitor’s productive horizontally-drilled Haynesville Shale wells. This amount was also due to a much lesser extent as a result of exploratory and developmental, or “step out”, drilling in our Johnson Branch acreage in fiscal 2009. The reserve estimates attributable to these new PUD locations are listed under “Extensions and discoveries.”
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Standardized measure of discounted future net cash flows relating to proved reserves:
The standardized measure of discounted future net cash flows was calculated by applying current year-end prices, considering fixed and determinable price changes only to the extent provided by contractual arrangements or law, to estimated future production, less future expenditures (based on fiscal year-end costs) to be incurred in developing proved undeveloped and proved producing oil and gas reserves, and future income taxes. The resulting future net cash flows were discounted using a rate of 10% per annum (Table 1). The standardized measure of discounted net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of the Company’s oil and gas proved by drilling or production history. There are significant uncertainties inherent in estimating timing and amount of future costs. In addition, the method of valuation utilized, is based on current prices and costs and the use of a 10% discount rate, and is not necessarily appropriate for determining fair value (Table 2).
The following is the estimated standardized measure relating to proved oil and gas reserves at June 30, 2009, 2008 and 2007:
Table 1
The following is an analysis of changes in the estimated standardized measure of proved reserves during the years ended June 30, 2009, 2008 and 2007:
Table 2
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note K - Selected quarterly financial data (unaudited):
Summarized unaudited quarterly financial data for fiscal 2009 and 2008 are as follows:
(1) The sum of the per share amounts per quarter does not equal the total year amount due to changes in the weighted average number of common shares outstanding in each quarter.
Note L - Subsequent Events
Subsequent events have been evaluated through September 25, 2009, which is the date the financial statements were issued.
On August 18 and August 26, 2009, Cubic Energy, Inc. (the “Company”) entered into Subscription and Registration Rights Agreements (the “Subscription Agreements”) with certain investors (the “Investors”). Pursuant to the Subscription Agreements, the Company issued 804,000 shares of common stock on August 18, 2009, and 1,300,001 shares of common stock on August 26, 2009, for an aggregate of 2,104,001 shares.
Pursuant to the Subscription Agreements, the Investors paid aggregate consideration of approximately $1,788,400 to the Company for 2,104,001 shares of the Company’s common stock and warrants exercisable into 1,052,000 shares of common stock. The warrants are exercisable through July 31, 2014, at $0.85 per share. With respect to certain of such issuances, the Company paid broker-dealer commissions in the aggregate amount of $59,500 to Avalon Securities, Ltd.
The shares and warrants were issued by the Company in reliance upon an exemption from registration set forth in Regulation D and/or Section 4(2) of the Securities Act of 1933, as amended, which exempts transactions by an issuer not involving a public offering.
CUBIC ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Note L - Subsequent Events (continued)
The Company has received an extensions of time until November 1, 2009 from Wells Fargo Energy Capital, Inc. (the “Lender”) to comply with the terms of that letter dated June 30, 2009. That June 30, 2009 letter previously informed the Company that the Lender made a borrowing base redetermination and waived any failure of the Company to comply with its obligations under the Credit Agreement as a result of such redetermination until September 1, 2009.
On September 15, 2009, the Company received notice from the NYSE Amex LLC (the “Exchange”) that the Exchange has accepted the Company’s previously submitted plan of compliance and, pursuant to such plan, has granted the Company an extension to regain compliance with the Exchange’s continued listing standards.
As previously disclosed on June 29, 2009, the Company received a letter from the Exchange indicating that the Exchange believes the Company is not in compliance with Section 1003(a)(iv), of the Exchange’s company guide based upon the Company’s financial condition. The Company was afforded the opportunity to submit a plan detailing how it intends to regain compliance with Section 1003(a)(iv) by December 28, 2009 and, on July 27, 2009, submitted such a plan to the Exchange. As a result, the Exchange has granted the Company an extension through December 28, 2009 to strengthen its financial condition and thereby evidence compliance with Section 1003(a)(iv).
The Company will be subject to periodic reviews by the Exchange during the extension period. Failure to make progress consistent with the plan or to regain compliance with the continued listing standards by the end of the extension period could result in the Company being delisted from the Exchange.
Note M - Going Concern
As shown in the accompanying financial statements, the Company incurred a net loss of $24,762,516 during the year ended June 30, 2009, and as of that date, the Company’s current liabilities exceeded its current assets by $27,822,536 and its total liabilities exceeded its total assets by $16,022,965. Those factors, as well as the uncertain conditions that the Company faces regarding its loan agreements, create an uncertainty about the Company’s ability to continue as a going concern. Management of the Company is developing a plan to reduce its liabilities through, among other alternatives, an expanded credit facility and issuance of additional stock to shareholders. The ability of the Company to continue as a going concern is dependent on acceptance of the plan by the Company’s bank creditors and the plan’s success. The financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
EXHIBIT INDEX
No.
Description
3.1
Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-QSB for the period ended September 30, 1999).
3.2
Articles of Amendment to the Articles of Incorporation of the Company dated December 30, 2005 (incorporated by reference to Exhibit 3.1 of the Company’s Form 10-QSB for the period ended December 31, 2005).
3.3
Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Form 10-KSB for the period ended June 30, 2000).
10.1
Registration Rights Agreement, effective as of September 30, 2004, among Cubic Energy, Inc. and the purchasers signatory thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on October 12, 2004).
10.2
Securities Purchase Agreement, dated as of December 12, 2005, among Cubic Energy, Inc. and each purchaser identified on the signature pages thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.3
Registration Rights Agreement, dated as of December 12, 2005, among Cubic Energy, Inc. and the purchasers signatory thereto (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.4
Form of Common Stock Purchase Warrant (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.5
Credit Agreement, dated February 6, 2006, by and among Cubic Energy, Inc. and Petro Capital V, L.P. (filed as exhibit 10.1 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.6
Common Stock Purchase Warrant, dated February 6, 2006, issued to Petro Capital Securities, LLC (filed as exhibit 10.3 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.7
Common Stock Purchase Warrant, dated February 6, 2006, issued to Petro Capital V, L.P. (filed as exhibit 10.4 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.8
Registration Rights Agreement, dated as of February 6, 2006, by and between Cubic Energy, Inc., Petro Capital V, L.P. and Petro Capital Securities, LLC (filed as exhibit 10.5 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.9
Purchase Agreement, dated as of February 6, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III, and Tauren Exploration, Inc. (filed as exhibit 10.6 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.10
Promissory Note, dated as of February 6, 2006, by Cubic Energy, Inc., payable to Tauren Exploration, Inc. in the principal amount of $1,300,000 (filed as exhibit 10.7 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.11
Amendment to Promissory Note, dated March 30, 2006, by and between, Cubic Energy, Inc. and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.8 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.12
Amendment to Purchase Agreement, dated April 3, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.9 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.13
Amendment to Purchase Agreement, dated May 5, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.10 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.14
Subscription and Registration Rights Agreement with George Karfunkel, dated July 26, 2006 (filed as Exhibit 10.1 to the Company’s Form 8-K dated July 28, 2006).
10.15
Subscription and Registration Rights Agreement with Yehuda Neuberger and Anne Neuberger JTWROS dated July 26, 2006 (filed as Exhibit 10.2 to the Company’s Form 8-K dated July 28, 2006).
10.16
Warrant issued to George Karfunkel (filed as Exhibit 10.3 to the Company’s Form 8-K dated July 28, 2006).
10.17
Warrant issued to Yehuda Neuberger and Anne Neuberger JTWROS (filed as Exhibit 10.4 to the Company’s Form 8-K dated July 28, 2006).
10.18
Third Amendment to Promissory Note, dated November 10, 2006, by and between, Cubic Energy, Inc. and Tauren Exploration, Inc. (filed as Exhibit 10.1 to the Company’s Form 10-QSB for the quarter ended September 30, 2006).
10.19
Warrant issued to Tauren Exploration, Inc. dated November 10, 2006 (filed as Exhibit 10.2 to the Company’s Form 10-QSB for the quarter ended September 30, 2006).
10.20
Form of Subscription and Registration Rights Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 21, 2006).
10.21
Form of Warrant (filed as Exhibit 10.2 to the Company’s Form 8-K filed December 21, 2006).
10.22
Credit Agreement dated March 5, 2007 by and between Cubic Energy, Inc. and Wells Fargo Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed March 9, 2007).
10.23
Convertible Promissory Note dated as of March 5, 2007 by Cubic Energy, Inc. payable to Wells Fargo Energy Capital, Inc. in the principal amount of $5,000,000 (filed as Exhibit 10.2 to the Company’s Form 8-K filed March 9, 2007).
10.24
Promissory Note dated as of March 5, 2007 by Cubic Energy payable to Wells Fargo Energy Capital, Inc. in the maximum principal amount of $20,000,000 (filed as Exhibit 10.3 to the Company’s Form 8-K on March 9, 2007).
10.25
Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc. dated March 5, 2007, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K on March 9, 2007).
10.26
Registration Rights Agreement dated as of March 5, 2007 by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.5 to the Company’s Form 8-K on March 9, 2007).
10.27
Form of Assignment of Net Profits Interest (filed as Exhibit 10.6 to the Company’s Form 8-K on March 9, 2007).
10.28
Employment Agreement with Calvin A. Wallen, III, dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008).
10.29
Employment Agreement with Jon S. Ross dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008).
10.30
Subordinated Promissory Note dated May 6, 2008 (filed as Exhibit 10.1 to the Company’s Form 10-QSB for the quarter ended March 31, 2008).
10.31
First Amendment to Credit Agreement with Wells Fargo Energy Capital dated May 8, 2008 (filed as Exhibit 10.2 to the Company’s Form 10-QSB for the quarter ended March 31, 2008).
10.32
Form of Subscription and Registration Rights Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 1, 2009).
10.33
Form of Warrant (filed as Exhibit 10.2 to the Company’s Form 8-K filed September 1, 2009).
23.1*
Consent of Philip Vogel & Co., PC
31.1*
Rule 13a-14(a)/15d-14(a) Certification of Calvin A. Wallen, III
31.2*
Rule 13a-14(a)/15d-14(a) Certification of Larry G. Badgley
32.1*
Section 1350 Certification of Calvin A. Wallen, III
32.2*
Section 1350 Certification of Larry G. Badgley
* Filed herewith.