Item 1. Business
Overview
GeoResources, Inc. (the “Company,” “we” or “us”), a Colorado corporation, is an independent oil and gas company engaged in the acquisition and development of oil and gas reserves through an active and diversified program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in the Southwest, Gulf Coast and the Williston Basin. Our corporate headquarters and Southern division operating offices are located in Houston, Texas, and our Northern division operating office is located in Denver, Colorado. We also have an additional operating office for the Northern division in Williston, North Dakota.
On April 17, 2007, the Company merged with Southern Bay Oil & Gas, L.P. (“Southern Bay”) and a subsidiary of Chandler Energy, LLC (“Chandler”) and acquired certain Chandler-associated oil and gas properties in exchange for 10,690,000 shares of common stock (collectively, the “Merger”). At the time of the Merger, the former Southern Bay partners received approximately 57% of the outstanding common stock of the Company and thus, acquired voting control. Although GeoResources was the legal acquirer, for financial reporting purposes the Merger was accounted for as a reverse acquisition of GeoResources by Southern Bay and an acquisition of Chandler and its associated properties.
During the course of 2007 and 2008, we transformed the Company from a small regional North Dakota-based company to a full scale exploration and production company with operations in multiple basins. As of December 31, 2008, we had an estimated 17,501 MBOE of proved reserves, associated with both our directly owned mineral interests (14,592 MBOE) and our partnership interests (2,909 MBOE), which were approximately 51% oil and 79% developed. See Item 2 of this report for estimates of our oil and gas reserves at December 31, 2008. Our production for the year ended December 31, 2008 totaled 1,236 MBOE or 3,387 BOE per day of which 60% was oil.
Recent Developments
Acquisition and Divestitures
In accordance with our business strategy, during 2008 we expanded our acreage positions and drilling inventory, implemented our drilling programs and high-graded the assets resulting from the Merger and significant acquisitions of 2007. We sold or abandoned certain properties which, collectively had a net production at the time of the sale of 316 Bbls/d and 742 Mcf/d, but were outside our focus areas, had limited development potential, short remaining productive lives, high maintenance requirements, or significant plugging obligations. We also acquired producing and undeveloped properties, principally in the Williston Basin and in Oklahoma. A summary of this activity is as follows:
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In January, 2008, we sold all of our interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was sold to an unaffiliated party for $6.6 million in cash. At the date of sale, the carrying value of this property was equal to the selling price; therefore, no gain or loss was recognized on the sale.
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In February, 2008, we acquired producing properties from an unaffiliated party in the Williston Basin of North Dakota and Montana for $7.9 million in cash. The acquired properties are operated by us.
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In February, 2008, we sold our interest in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million and recognized gains of $430,000.
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In May, 2008, we sold seven non-core oil and gas properties in Louisiana and Texas for approximately $11.8 million. We recognized a gain of $1.5 million related to these sales.
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In May, 2008, Catena Oil & Gas LLC (“Catena”), a wholly-owned subsidiary of the Company, participated in the formation of OKLA Energy Partners LP (“OKLA”) in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. The acquisition totaled $61.7 million. Catena directly purchased 18% of the interests and OKLA purchased the remaining 82%. Catena, the general partner for OKLA, has a 2% partnership interest. Under the terms of the partnership agreement, Catena’s general partner interest can increase to approximately 36% pending certain performance hurdles.
Index to Financial Statements
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In September, 2008, we acquired producing properties in Oklahoma from an unaffiliated party for $3.6 million in cash.
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During 2008, we identified an exploration opportunity in the Paradox Basin and began leasing in Colorado and Utah targeting the Gothic shale, as a newly emerging resource play with multiple objectives. In the fourth quarter of 2008, we sold a majority of our interest for $6 million and recognized a gain of $2.5 million. We retained an option to participate, up to a 12.5% working interest, in any future drilling on the acreage.
Long Term Debt
On October 16, 2007, we entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”) with a bank that provides for financing of up to $200 million. The Amended Credit Agreement provided for interest at either (a) the London Interbank Offered Rate (“LIBOR”) plus 1.5% to 2.25%, or (b) the prime lending rate of the bank plus .5% to 1.25%, depending on principal amounts outstanding. All amounts outstanding under this Amended Credit Agreement are due and payable in full at maturity on October 16, 2010. The initial borrowing base was $110 million. On September 30, 2008, the borrowing base had been reduced to $95 million due to the sales of certain non-core oil and gas properties. On November 5, 2008, the borrowing base was increased to $100 million and the Amended Credit Agreement was amended to provide for interest rates at either, (a) LIBOR plus 1.75% to 2.50%, or (b) the prime lending rate plus .75% to 1.50%, depending on the amount borrowed. On March 13, 2009, in connection with the borrowing base redetermination due April 1, 2009, we were advised that our lead bank will recommend that the $100 million borrowing base be extended to the next redetermination. Approval is required by the bank group and is presently expected in early April.
Private Placement
On June 5, 2008, we issued 1,533,334 shares of our common stock and 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The shares of common stock were sold for $22.50 per share. The warrants have a term of five years with an exercise price of $32.43 per share. The gross proceeds of $34.5 million were reduced by private placement fees and issue costs of $2.3 million.
Our Business Strategy
We implemented our business strategy upon the closing of the Merger. Our strategy includes a combination of acquisition, re-engineering, development and exploration activities. We first focus on building reserves and cash flows and then expand acreage, development and exploration inventory. Further, our strategy includes activities with geological and geographical diversity.
Our business strategy includes:
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acquiring additional oil and gas reserves through asset or corporate acquisitions or mergers;
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expanding acreage and prospect inventory through internal generation of new projects and selective prospect participations with other capable oil and gas operators;
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comprehensive field re-engineering, designed to increase and maintain production, lower per-unit operating expenses, and therefore, improve field economics; and
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development, exploitation and exploration activities intended to increase production and estimated proved reserves.
This fundamental operating and technical strategy is complemented by management’s commitment to:
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maintain a fundamentally sound capital structure which provides the Company a low cost of capital;
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control capital, operating and administrative costs;
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hedge a portion of total production to provide a foundation of predictable cash flows to support development and exploration activities;
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divest non-core assets to high-grade our portfolio of properties; and
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promote industry and institutional partners into projects to manage risk and to lower net finding and development costs.
In the opinion of management, our strategy is appropriate for us because:
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it addresses multiple risks of oil and gas operations while providing shareholders with significant upside potential;
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it results in “staying-power,” which management believes is essential to mitigate the adverse impacts of volatile commodity prices and financial markets; and
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it is a strategy employed successfully in prior entities formed, acquired and operated by management.
Each component of our business strategy and related matters are briefly discussed below.
Acquisitions and Divestitures - Acquisitions of oil and gas properties and/or companies in conjunction with exploration and development activities are intended to allow us to assemble a portfolio of properties with the potential for meaningful economic returns from (1) the application of operational and technical attention, (2) development of non-producing reserves, and (3) realization of exploration upside. We seek to acquire oil and gas interests with the characteristics of manageable risks, fairly predictable production and value enhancement potential. An ongoing part of our portfolio approach is the divestiture of non-core assets in order to streamline and high-grade our oil and gas property portfolio. Divestitures of this type of properties are an integral part of our strategy.
Development Activities - We are also focused on development and exploitation of non-producing reserves. We conduct comprehensive field studies, which usually result in:
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Re-engineering projects with the intent to lower per-unit operating expenses and/or reduce field down-time. In addition, we seek to implement more efficient production practices in order to increase production and/or arrest natural field production declines. These practices are often deployed in fields in connection with or in anticipation of further field development activities such as installation of secondary recovery operations or additional drilling.
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Development and exploration projects resulting from the integration of operations and reservoir engineering with geology and geophysics. When applicable, 3-D seismic technology is utilized. Our objective is to develop specific projects to recover bypassed or undeveloped reserves and define exploration potential.
Exploration - We believe our management and technical personnel have the experience and capability to expand our acreage positions and drilling inventory, and accordingly, we expect to continue to expand our exploration activities as our asset base increases. This strategy has three distinct purposes:
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expand our inventory of substantive acreage and prospects;
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fully develop acquired properties; and
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realize substantial economic returns from exploration.
While we intend to dedicate a meaningful portion of our budget to exploration and drilling, as the geological objectives move to a higher risk and cost profile, industry or institutional partners may be solicited on a promoted basis where we sell part of the project in exchange for cash and/or a carried interest.
Corporate Mergers and Acquisitions - As a distinct part of our overall strategy, we continue to pursue corporate merger and acquisition opportunities. Criteria for such acquisitions might include, but are not limited to:
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the potential to increase assets in a core area;
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the opportunity to increase our earnings and cash flow;
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development and exploration potential;
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the ability to refinance debt and attract capital; and
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realization of administrative savings.
In summary, we believe these diversified business strategies and methodical processes will maintain the reserve and production base and lead to growth in reserves, production, cash flow and consequently, in per share values.
Index to Financial Statements Oil and Gas Exploration and Development
Our oil and gas exploration and production efforts are concentrated on oil and gas properties in our areas of operations. We typically generate prospects for our own exploitation, but when we believe a prospect may have substantial risk or cost, we may partially finance our drilling activities through the sale of participations to industry or institutional partners on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs. For example, we may enter into farm-outs, joint ventures, or other similar types of cost-sharing arrangements to reduce our overall capital cost. The amount of interest retained by us in a cost-sharing arrangement varies widely and depends upon many factors, including the exploratory costs and the risks involved.
Marketing of Production
Our oil and gas production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field posted prices or market indices, plus or minus adjustments for quality or transportation. Natural gas is usually sold under a contract at a negotiated price based upon factors normally considered in the industry, such as quality, distance from the well to the pipeline and liquid hydrocarbon content, and prevailing supply/demand conditions.
Backlog Orders, Research and Development
Our oil and gas sales contracts and off-lease marketing arrangements are generally standard industry contracts with 30 to 90 day cancelation notice provisions. We do not have any contracts to supply crude oil or natural gas which exceed one year. We have not spent any material time or funds on research and development and do not expect to do so in the foreseeable future. In addition, as discussed elsewhere, we have entered into long-term commodity hedge contracts to mitigate the effects of price declines of oil and natural gas.
Competition
In addition to being highly speculative, the oil and gas business is highly competitive among many independent operators and major oil companies in the industry. Many competitors possess financial resources and technical facilities greater than those available to us and they may, therefore, be able to pay for more desirable properties or find more potentially productive prospects.
Environmental Regulations
Our operations are generally subject to numerous stringent federal, state and local environmental regulations under various acts including the Comprehensive Environmental Response, Compensation and Liability Act, the Federal Water Pollution Control Act, and the Resources Conservation and Recovery Act. For example, our operations are affected by diverse environmental regulations including those regarding the disposal of produced oilfield brines, other oil-related wastes, and additional wastes not directly related to oil and gas production. Additional regulations exist regarding the containment and handling of crude oil as well as preventing the release of oil into the environment. It is not possible to estimate future environmental compliance costs due in part, to the uncertainty of continually changing environmental initiatives. While future environmental costs can be expected to be significant to the entire oil and gas industry, we do not believe that our costs would be any more of a relative financial burden than others in our industry.
Foreign Operations and Export Sales
We do not have any interests, production facilities, or operations in foreign countries
Employees
As of December 31, 2008, we had 52 full-time employees, 34 of which are management, technical and administrative personnel, and 18 are field employees. Contract personnel operate some of our producing fields under the direct supervision of our employees. We consider all relations with our employees to be good.
Index to Financial Statements Available Information
We maintain a website at the address www.georesourcesinc.com. We are not including the information contained on our website as part of, or incorporating it by reference into this report. Through our website, we make available our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we file such material with the SEC.
Item 1A.
Item 1A. Risk Factors
Set forth below are risks with respect to our Company. Readers should review these risks, together with the other information contained in this report. The risks and uncertainties we have described in this report are not the only ones we face. Additional risks and uncertainties not presently known to us, or that we deem immaterial, may also adversely affect our business. Any of the risks discussed in this report that are presently unknown or immaterial, if they were to actually occur, could result in a significant adverse impact on our business, operating results, prospects and/or financial condition.
We are dependent upon the services of our chief executive officer and other executive officers.
We are dependent upon a limited number of personnel, including Frank A. Lodzinski, our Chief Executive Officer and President, and other management personnel and key employees. Failure to retain the services of these persons, or to replace them with adequate personnel in the event of their departure or termination, may have a material adverse effect on our operations. No employment agreements with any of our officers currently exist, but we may consider such agreements in the future. We have no key-man life insurance on the lives of any of our executive officers.
We must successfully acquire or develop additional reserves of oil and gas.
Our future production of oil and gas is highly dependent upon our level of success in acquiring or finding additional reserves. The rate of production from our oil and gas properties generally decreases as reserves are produced. We may not be able to acquire or develop oil and gas properties economically due to a lack of drilling success as well as lack of capital and inability to obtain adequate financing, which may be required to fund prospect generation, drilling operations and property acquisitions.
Intense competition in the oil and gas exploration and production segment could adversely affect our ability to acquire desirable properties prospective for oil and gas, as well as producing oil and gas properties.
The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which could, in the future, make acquisitions of producing properties at economic prices difficult for us. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also face significant competition in attracting and retaining experienced, capable and technical personnel, including geologists, geophysicists, engineers, landmen and others with experience in the oil and gas industry.
We may be faced with shortages of personnel and equipment, thereby adversely affecting operations and financial results.
The oil and gas industry, as a whole, suffers from an aging workforce and shortage of qualified and experienced personnel. Our operations and financial results may be adversely impacted due to difficulties in attracting and retaining such personnel within our Company or within companies that provide materials and services to the industry. Additional personnel are likely to be required in connection with our expansion plans, and the domestic oil and gas industry has in the past experienced significant shortages of qualified personnel in all areas of
Index to Financial Statements
operations. Further, our expansion plans will likely require access to services and oil field equipment. Such equipment and operating personnel may be in short supply. The substantial decrease in commodity prices has resulted in decreased drilling and construction activity in the industry and shortages of personnel and equipment has recently eased, but nevertheless shortages of qualified and experienced personnel still exist.
Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.
Our success will be largely dependent on oil and natural gas prices, which are highly volatile. During 2008 such prices reached historically high levels only to fall dramatically in the later part of the year. Significant further declines in the price of oil and natural gas will have a negative impact on our business operations and future revenues. Moreover, oil and natural gas prices depend on factors that are outside of our control, including:
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economic and energy infrastructure disruptions caused by actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in the Middle East, Nigeria and Venezuela;
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weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;
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changes in the global oil supply, demand and inventories;
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changes in domestic natural gas supply, demand and inventories;
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the price and quantity of foreign imports of oil;
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the price and availability of liquified natural gas imports;
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political conditions in or affecting other oil-producing countries;
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general economic conditions in the United Stated and worldwide;
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the level of worldwide oil and natural gas exploration and production activity;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
Lower oil and natural gas prices not only decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can economically produce. Lower prices also negatively impact estimates of our proved reserves. Substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity or ability to finance operations and planned capital expenditures.
Industry changes may adversely affect various financial measurements and negatively affect the market price of our common stock.
Although we believe that our business strategy has and will continue to allow us to continue our growth and increase operating efficiencies, unforeseen costs and industry changes, as listed below, could potentially have an adverse effect on return of capital and earnings per share. Future events and conditions could cause any such changes to be significant, including, among other things, adverse changes in:
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commodity prices for oil, natural gas and liquid natural gas, such as occurred in 2008;
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reserve levels;
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operating results;
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capital expenditure obligations; and
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production levels.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks including the possibility of:
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blowouts, fires and explosions;
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personal injuries and death;
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uninsured or underinsured losses;
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unanticipated, abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination.
Any of these operating hazards could cause damage to properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, which could expose us to liabilities. Although we believe that we are adequately insured for replacement costs of our wells and associated equipment, the payment of any of these liabilities could reduce the funds available for exploration, development, and acquisition, or could result in a loss of our properties. Also, as is customary in the oil and gas business, we do not carry business interruption insurance.
The insurance market in general and the energy insurance market in particular have recently experienced substantial cost increases from 2007 to 2008. It is possible that we will determine not to purchase some insurance because of high insurance premiums. If we incur substantial liabilities and the damages are not fully covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition would likely be materially adversely affected.
We have hurricane associated risks in connection with our operations in the Texas and Louisiana Gulf Coast.
We could be subject to production curtailments resulting from hurricane damage to certain fields or, even in the event that producing fields are not damaged, production could be curtailed due to damage to facilities and equipment owned by oil and gas purchasers, or vendors and suppliers, because a portion of our oil and gas properties are located in or near coastal areas of the Texas and Louisiana Gulf Coast. In the third quarter of 2008, hurricanes Gustav and Ike damaged certain production facilities, located in the state waters of Louisiana. As a result, production volumes for the third quarter were down by approximately 15,800 net barrels of oil. Oil production started to be restored in phases in late October and as of year-end was fully restored. We incurred additional operating and capital expenditures as a result of the hurricanes of approximately $1.1 million and expect to recoup $685,000 from insurance proceeds. Considering significant cost increases associated with “wind-storm” insurance coverage, we may increase our insurance deductibles or otherwise modify coverage.
If oil and gas prices decrease or exploration efforts are unsuccessful, we may be required to write-down the capitalized cost of individual oil and gas properties.
A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful. A writedown could adversely affect the trading prices of our common stock.
We use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.
The capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, pursuant to generally accepted accounting principles, we are required to record impairment charges to reduce the capitalized costs of each such field to its estimate of the field’s fair market value, even though other fields may have increased in value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce earnings and shareholders’ equity.
Index to Financial Statements Revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.
The market price of our common stock may be subject to significant decreases due to decreases in estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.
In addition, the estimates of future net cash flows from proved reserves and the present value of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.
Our hedging activities may prevent us from realizing the benefits in oil or gas price increases.
In an attempt to reduce our sensitivity to oil and gas price volatility, we have, and will likely continue to, enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. In a typical hedge transaction, we may fix the price, a floor or a range, on a portion of our production over a predetermined period of time. It is expected that we will receive from the counter-party to the hedge payment of the excess of the fixed price specified in the hedge contract over a floating price based on a market index, multiplied by the volume of the production hedged. Conversely, if the floating price exceeds the fixed price, we would be required to pay the counter-party such price difference multiplied by the volume of production hedged. There are numerous risks associated with hedging activities such as the risk that reserves are not produced at rates equivalent to the hedged position, and the risk that production and transportation cost assumptions used in determining an acceptable hedge could be substantially different from the actual cost. In addition, the counter-party to the hedge may become unable or unwilling to perform its obligations under hedging contracts, and we could incur a material adverse financial effect if there is any significant non-performance. While intended to reduce the effects of oil and gas price volatility, hedging transactions may limit potential gains earned by us from oil and gas price increases and may expose us to the risk of financial loss in certain circumstances.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.
Our success will depend on the results of our exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Furthermore, many factors may curtail, delay or cancel drilling, including:
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shortages of or delays in obtaining equipment and qualified personnel;
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pressure or irregularities in geological formations;
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equipment failures or accidents;
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adverse weather conditions;
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reductions in oil and natural gas prices;
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issues associated with property titles; and
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delays imposed by or resulting from compliance with regulatory requirements.
Index to Financial Statements Existing debt and use of debt financing may adversely affect our business strategy.
We have used debt to fund a portion of our acquisition activities and we will likely use debt to fund a portion of our future acquisition activities. Any temporary or sustained inability to service or repay debt will materially adversely affect our results of operations and financial condition and will materially adversely affect our ability to obtain other financing.
The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.
The continued credit crisis and related turmoil in the global financial system, as well as the global economic recession, may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. The current economic situation could have a material adverse impact on our lenders or customers causing them to fail to meet their obligations to us. Additionally, market conditions could have a materially adverse impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. Also, the current economic worldwide situation could lead to further reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a material negative impact on our revenues, results of operations and financial conditions.
Due to the current state of the financial markets, we may have significantly reduced access to public and private capital as well as substantially higher costs of capital if we are able to obtain capital.
Oil and gas activities are capital intensive. Historically, we have obtained equity and debt capital to fund our growth strategy. We may require additional equity capital in order to pursue our business strategy and avoid excessive debt levels. Considering the current state of the worldwide economy and the financial markets, we may not be able to attract investors that would provide equity capital to us at all, or the costs to obtain such capital may be unreasonable. To the extent that we may attract capital, the costs of such capital could increase appreciably and such capital may take forms, such as preferred stock or convertible debt, which would be senior to our common stock. We believe that the ability to attract capital at reasonable costs is critical to our long-term growth strategy, particularly due to the depleting nature of oil and gas operations.
We are obligated to comply with financial and other covenants in our existing Amended Credit Facility that could restrict our operating activities, and the failure to comply could result in defaults that accelerate the payment under our debt.
Our Amended Credit Facility generally contains customary covenants, including, among others, provisions:
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relating to the maintenance of the oil and gas properties securing the debt; and
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restricting our ability to assign or further encumber the properties securing the debt.
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all of our obligations under the Amended Credit Facility are secured by substantially all of our assets.
In addition, our Amended Credit Facility requires us to maintain financial covenants, including, but not limited to the following:
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a current ratio of not less than 1.0 to 1.0 excluding current hedge obligations;
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a funded debt to EBITDA ratio of not greater than 4.0 to 1.0; and
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an interest coverage ratio, which is the ratio of the EBITDA for the four most recently completed quarters ending on such date compared to the cash interest payments made for such fiscal quarters, of not less than 3.0 to 1.0.
As of the date of this report, we were in compliance with all such covenants. If we were to breach any of our debt covenants and not cure the breach within any applicable cure period, the Lender could require us to repay the debt immediately, and if the debt is secured, could immediately begin proceedings to take possession of substantially all of our properties. Any such property losses would materially and adversely affect our cash flow and results of operations.
Index to Financial Statements Our properties may be subject to influence by third parties that do not allow us to proceed with planned explorations and expenditures.
We are the operator of a majority of our properties, but for many of our properties we own less than 100% of the working interests. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the “operator” of the property. For properties where we own less than 100% of the working interest, whether operated or non-operated, drilling and operating decisions may not be within our sole control. If we disagree with the decision of a majority of working interest owners, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.
Recent legislative proposals could materially lessen the economic viability of domestic exploration and production companies, including us.
The recent budgetary proposals of the Obama Administration, if enacted into law by Congress, could have a material adverse impact on the domestic oil and gas industry and on exploration and production companies in particular. The proposals Would eliminate the so called “oil and gas company preferences” worth an estimated $31.5 billion over 10 years and raise other taxes on the industry. The proposed budget would eliminate tax mechanisms critical to capital formation for drilling, such as expensing of intangible drilling costs and eliminating the percentage depletion allowance, and if enacted, would have a significant adverse impact on domestic drilling for oil and natural gas. The proposed budget would also charge producers user fees for processing permits to drill on federal lands and increase royalty rates of minerals produced from federal lands. We cannot predict the outcome of the proposed U.S. Government budget, but the enactment of any of the proposals would likely adversely affect the domestic oil and gas exploration and production business by making future production more difficult and expensive, thereby lessening the economic viability of these companies, of which we are part.
There are a substantial number of shares of our common stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.
There were 16,241,717 shares of our common stock outstanding as of March 20, 2009.
Members of our management and other affiliates owned approximately 8,999,183 shares of our common stock, representing 55% of our outstanding common stock as of March 20, 2009. Sale of a substantial number of these shares would likely have a significant negative affect on the market price of our common stock, particularly if the sales are made over a short period of time. These shares may be sold publicly pursuant to an effective registration statement with the SEC.
If our stockholders, particularly management and their affiliates, sell a large number of shares of our common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could depress the market price of those shares.
Recovery of investments in acquiring oil and gas properties is uncertain.
We cannot assure that we will recover the costs we incur in acquiring oil and gas properties. While the acquisition and development of oil and gas properties is based on engineering, geological and geophysical assessments, such data and analysis is inexact and inherently uncertain. There can be no assurance that any properties we acquire will be economically produced or developed. Re-engineering operations pose the risk that anticipated benefits, which may include reserve additions, production rate improvements or lower recurring operating expenses, may not be achieved, or that actual results obtained may not be sufficient to recover investments. Drilling activities, whether exploratory or developmental, are subject to mechanical and geological risks, including the risk that no commercially productive reservoirs will be encountered. Unsuccessful acquisitions, re-engineering or drilling activities could have a material adverse effect on our results of operations and financial condition.
Index to Financial Statements We cannot assure we would be able to achieve continued growth in assets, production or revenue.
There can be no assurance that we will continue to experience growth in revenues, oil and gas reserves or production. Any future growth in oil and gas reserves, production and operations will place significant demands on us and our management and personnel. Our future performance and profitability will depend, in part, on our ability to successfully integrate acquired properties into our operations, develop such properties, hire additional personnel and implement necessary enhancements to our management systems.
The nature of our business and assets may expose us to significant compliance costs and liabilities.
Our operations involving the exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict, inhibit or prohibit our operations; or claims of damages to property or persons.
Compliance with environmental laws and regulations may require us to spend significant resources.
Environmental laws and regulations may: (1) require the acquisition of a permit before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state environmental laws and regulations could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in compliance with applicable environmental and other governmental laws and regulations. There can be no assurance, however, that significant costs for environmental regulatory compliance will not be incurred by us in the future, thereby having an adverse effect on our ability to conduct our business profitably.
Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
Index to Financial Statements
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Offices
Our principal offices are located at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, where we occupy approximately 14,000 square feet of office space. This lease provides for gross rent of $220,080 per year and expires on October 31, 2010. Our Northern Region office, consisting of approximately 3,600 square feet, is located at 475 17th Street, Suite 1210, Denver, Colorado 80202. The Denver lease provides for gross rent of $77,190 per year for 2009 and expires on January 31, 2011. Our Williston office consists of approximately 4,000 square feet and is located at 1407 West Dakota Parkway, Williston, North Dakota 58801. The Williston lease provides for gross rent of $24,000 per year for 2009 and expires on December 31, 2010. We currently expect to renew all of our office leases upon expiration.
Index to Financial Statements Oil and Gas Reserve Information
All of our oil and gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of our proved reserves and the standardized measure of future net cash flows from the reserves is presented in Note N to the Consolidated Financial Statements. The estimates are based upon the reports of Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. We have no long-term supply or similar agreements with foreign governments or authorities.
Set forth below is a summary of our oil and gas reserves as of December 31, 2008. All of our reserves are located in the United States. We did not provide any reserve information to any federal agencies in 2008 other than to the SEC.
Oil and Gas Reserve Quantities
(1) Present Value Discounted at 10% (“PV10”) is a Non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of PV10 value is relevant and useful to our investors because it presents the estimated discounted future net flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses, the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties.
Index to Financial Statements PV10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For presentation of the standardized measure of discounted future net cash flows, please see “Note N: Supplemental Financial Information for Oil and Gas Producing Activities” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this Annual Report on Form 10-K. The table below provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.
Partnership operations and reserves as of December 31, 2008 (not included above):
The reserve quantities and values shown above do not include our interest in two affiliated partnerships.
We hold direct working interests in the Giddings Field (discussed further below) and we also hold the general partner interest of a partnership, SBE Partners, LP (“SBE Partners”) which owns controlling interests in the producing wells and developmental acreage in that field. Our 2% partnership interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return.
We hold direct working interests in producing oil and gas properties located throughout Oklahoma and we also hold the general partner interest of a partnership, OKLA Energy Partners, LP (“OKLA”) which owns a larger interest in those same producing oil and gas properties. Our 2% partnership interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return.
The following table represents our estimated share (inclusive of our reversionary interests) of the affiliated partnerships’ reserves and estimated present value of future net income discounted at 10% (in thousands of dollars), using SEC guidelines.
Index to Financial Statements Non-GAAP Reconcilation
The following table reconciles our direct interest in oil and gas reserves (in thousands):
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.
Index to Financial Statements Net Oil and Gas Production, Average Price and Average Production Cost
The net quantities of oil and gas produced and sold by us for each of the three fiscal years ended December 31, the average sales price per unit sold and the average production cost per unit are presented below.
* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE).
** Average production cost includes lifting costs, remedial workover expenses and production taxes.
Our production is sold to large petroleum purchasers. Due to the quality and location of our crude oil production, we may receive a discount or premium from index prices or “posted” prices in the area. Our gas production is sold primarily to pipelines and/or gas marketers under short-term contracts at prices which are tied to the “spot” market for gas sold in the area.
In 2008, one purchaser accounted for 16% of our consolidated oil and gas revenue, two more accounted for 11% each and two purchasers accounted for 10% each of our oil and gas revenues. In 2007, two purchasers accounted for 17% and 14% of our consolidated oil and gas revenues. In 2006, four purchasers accounted for 27%, 18%, 15% and 12% of our consolidated oil and gas revenues. No other single purchaser accounted for 10% or more of our oil and gas revenues in 2008, 2007, or 2006. There are adequate alternate purchasers of our production such that we believe the loss of one or more of the above purchasers would not have a material adverse effect on our results of operations or cash flows.
Gross and Net Productive Wells
As of December 31, 2008, our total gross and net productive wells were as follows:
Productive Wells *
* There are no wells with multiple completions. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractions of working interests we own in gross wells. Productive wells are producing wells plus shut-in wells we deem capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well.
Index to Financial Statements Gross and Net Developed and Undeveloped Acres
As of December 31, 2008, we had total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated by state regulatory authorities.
Gross acres are those acres in which working interest is owned. The number of net acres represents the sum of fraction working interests we own in gross acres.
Exploratory Wells and Development Wells
Set forth below for the three years ended December 31, is information concerning the number of wells we drilled during the years indicated.
Subsequent to year-end we drilled three exploratory dry holes; the costs incurred through December 31, 2008, are included in exploration expense.
Present Activities
At March 20, 2009, we had 7 gross (0.37 net) wells in the process of drilling or completing.
Supply Contracts or Agreements
As December 31, 2008, we are not obligated to provide any fixed or determinable quantities of oil and gas in the future under any existing contracts or agreements, beyond the short-term contracts customary in division orders and off lease marketing agreements with the industry. In March, 2009, we entered into a forward sales contract for a portion of the crude oil sales on several of our Northern Region properties. The contract obligates us to sell 300 Bbls/d at a fixed price of $40.80. The contract term begins April, 2009 and runs through March, 2010. We also engage in hedging activities as discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Index to Financial Statements Summary of our Producing Properties
The following is a description of our noteworthy producing fields that provide a production base for our continued operations. We believe that many of these fields have upside exploitation potential. See also “Exploration and Exploitation” below.
Black Warrior Basin - located in Alabama and Mississippi. These properties include several fields with 36 producing wells. Production is from conventional reservoirs consisting of Mississippian-aged sands. Some wells are on rod-pump while the majority of the wells flow directly into low pressure gathering systems. The current aggregated gross production rate is 1.45 MMcf/d. The majority of the wells are operated by the Company, which has an average working interest of 60% and an average net revenue interest of 46%.
Chittim Field - located in Maverick County, Texas. The field consists of 43 gross producing wells which produce from the Cretaceous Glen Rose interval. All of the wells flow into a low pressure gathering system at a current aggregate gross rate of 3.62 MMcf/d. The majority of the wells are horizontal producers. The field is operated by the Company, which has an average working interest of 47% and an average net revenue interest of 36%.
Driscoll Field - located in Duval County, Texas. This field consists of 41 gross producing wells, which produce from the Jackson/Yegua interval. The majority of the field produces with the aid of rod pumps and the current aggregate gross production rate is 164 Bbls/d and 361 Mcf/d. The field is operated by the Company, which has an average working interest of 98% and an average net revenue interest of 86%.
East Nesson Bakken Area - Located in Mountrail County, North Dakota. The area is being developed by numerous operators and we have varying working interests ranging from 10% to 15% and net revenue interests ranging from 8.2% to 12.3% in approximately 35,000 acres. Our participation in this field is primarily through a joint venture with another Williston Basin operator. To date, 13 joint venture wells have been drilled by that operator and we also have nominal interests in another 24 wells that are producing or are in various stages of completion. Current production net to our interest is approximately 100 Bbls/d.
Eloi Bay Field Complex - located in state waters offshore St. Bernard Parish, Louisiana. The field (including the adjacent Chandler Sound Block 71) is located in 5-10 feet of water. This non-operated field complex has 46 gross producing wells on gas lift - all completed in the Miocene section. Current aggregate gross production is 1,077 Bbls/d. The Company’s working interest varies between 12.5% and 50%. Across the field as a whole, the average working interest is 46% and the average net revenue interest is 39%.
Frisco and Fordoche Fields - located in Pointe Coupee Parish, Louisiana. These fields consist of 23 gross producing wells, which produce from the Frio and multiple Wilcox Sand intervals. All of the wells are on rod-pump or hydraulic lift with an aggregate current gross rate of 384 Bbls/d. Both fields are operated by the Company, which has an average working interest of 70% and an average net revenue interest of 55%.
Giddings Field - located in Brazos, Burleson, Fayette, Grimes, Lee, Montgomery and Washington Counties, Texas. These properties consist of 63 gross producing wells, which produce from the Cretaceous Austin Chalk interval. All of the wells are horizontal producers utilizing rod pumps, compression, and other methods to produce the current aggregate gross rate of 111 Bbls/d and 48.36 MMcf/d. The field is operated by the Company, which has an average direct working interest of 6.7% and a net revenue interest of 5.2%. In Grimes County, however, where a majority of production and development is located, the Company has a direct working interest of 7.2% and average net revenue interest of 5.6%. In addition, the Company is the General Partner of a partnership which owns an average 77% working interest with an average 66% net revenue interest in 61,333 gross (55,200 net) acres. The Company’s 2% partnership interest reverts to 35.66% when the partnership realizes a contractually specified rate of return.
Harris Field - located in Gaines County, Texas. The field consists of six gross producing wells, which produce from the San Andres interval. The field produces with the aid of rod pumps and the current gross production rate is 57 Bbls/d. The field is operated by the Company, which has an average working interest of 76% and an average net revenue interest of 57%.
Index to Financial Statements Landa West Madison Unit / Northeast Landa Field - located in Bottineau County, North Dakota. These two fields consist of 14 gross producing wells, which produce from the Spearfish and Mississippian Madison intervals. Both fields are operated by the Company, which has an average working interest of 92% and average net revenue interest of 78%. The current gross production is 66 Bbls/d.
MAK Field - located in Andrews County, Texas. This field consists of nine gross producing wells, which produce from the Spraberry interval. The field produces with the aid of rod pumps and the current gross production rate is 145 Bbls/d and 52 Mcf/d. The field is operated by the Company, which has an average working interest of 91% and an average net revenue interest of 71%.
New Mexico Fields - located in Eddy and Lea Counties, New Mexico. This area consists of three fields with 37 gross producing wells. Production is from the Seven Rivers, Queen, Grayburg and San Andres formations. The wells are on rod pumps and the current aggregate gross production rate is 88 Bbls/d. The fields are operated by the Company, which has an average working interest of 94% and an average net revenue interest of 76%.
Odem Field - located in San Patricio County, Texas. This field consists of 67 gross producing wells, which produce from multiple Frio Sands. The fields produce with the aid of rod pumps, compression and gas lift with the current gross production rate of 143 Bbls/d and 2.01 MMcf/d. The field is operated by the Company, which has an average working interest of 48% and net revenue interest of 37%.
Quarantine Bay Field - located in State waters offshore Plaquemines Parish, Louisiana. The field is located in 6-15 feet of water. The non-operated field has 31 gross producing wells completed above 10,500 feet. All of the wells produce with the aid of gas lift equipment. Current field gross production is approximately 910 Bbls/d and 104 Mcf/d. The Company has an average working interest in these wells of 7.0% and an average net revenue interest of 5.2%. The Company, however, has a 33% working interest in exploration acreage below 10,500 feet and rights which are held by production (see “Exploration and Exploitation” discussion below).
Sherman/Wayne Fields - located in Bottineau County, North Dakota. These fields consist of 19 gross producing wells, which produce from the Mississippian Wayne interval. These fields are operated by the Company, which has an average working interest of 80% and an average net revenue interest of 67%. The current gross production of these fields is 259 Bbls/d.
St. Martinville Field - located in St. Martin Parish, Louisiana. The field consists of 16 gross producing wells, which produce from numerous Miocene sand intervals. The wells are on rod-pump or electric submersible pumps and have a current gross production rate of 392 Bbls/d. The field is operated by the Company, which has an average working interest of 97%. The Company owns the majority of the minerals resulting in a net revenue interest of approximately 91%.
Starbuck Madison Unit and Southwest Starbuck Field - located in Bottineau County, North Dakota. The Starbuck Madison Field has been unitized and water-flood operations are underway. The Starbuck Madison Unit includes 14 gross producing wells and three active injectors as well as and two additional drilled but not yet completed injection wells. The unit produces from the Mississippian Madison interval. The capital plan was divided into phases. Phase one was completed February, 2008, phase two began in the fourth quarter, 2008, and was recently completed. The field is operated by the Company, which has an average working interest of 96% and an average net revenue interest of 83%. The gross production from the field is currently 56 Bbls/d and can increase significantly pending successful flood performance. The Company also has successfully unitized the Southwest Starbuck Field which includes 560 gross acres. The Company has a 97.52% working interest, a 75.42% net revenue interest and has completed the initial phase of water flood operations in connection with phase two of the larger Starbuck Madison Unit, which is in close proximity and can share certain facilities, thereby enhancing the economics of both units.
Exploration and Exploitation
Our producing properties have reasonably predictable production profiles, earnings and cash flows and thus provide a foundation for our technical staff to further develop our existing properties and also generate new projects that we believe have the potential to increase our share value. We believe that many of our existing fields have
Index to Financial Statements
exploration and exploitation potential, much of which is presently defined. The steep and rapid decline of commodity prices in 2008 and the collapse of the capital markets have caused numerous independents to significantly reduce their capital budgets. While we have not yet reduced our capital budget, some of our projects, particularly those that are held by production, have been deferred in favor of projects with lease expirations. In addition, some projects in North Dakota have been deferred as a result of prices being adversely affected by increased transportation and quality deductions. In some cases, these projects were replaced by Gulf Coast projects with better current commodity prices. Our capital budget is discussed more fully in Item 7. The table and discussion below, while not all inclusive, present a broad range of projects and prospects in various stages of development.
Exploration and Exploitation Acreage We attempt to establish production operations in areas of interest and expand exploration and exploitation opportunities in those fields and regional proximity thereto. The table below is presented to summarize certain acreage positions associated with exploration and exploitation opportunities. The acreage table is not all inclusive but summarizes the field discussions below.
(1) Includes acreage held by us and our affiliated partnership, see Partnership Reserves and discussion of the Giddings field included above.
(2) Represents acreage in multiple fields, includes acreage held by GeoResources and its affiliated partnership
(3) Represents net exploration acreage held by shallow production. See discussion below.
Chittim Field (also discussed above) - We have 12,822 gross and 6,411 net acres in the field. The field presently produces out of the Glen Rose interval and the upside potential includes an additional three proved and probable undeveloped locations. The Maverick Basin, however, has additional plays and targets including the Pearsall and Eagleford shale. We have budgeted a horizontal offset well to a vertical Pearsall well that produced and we believe horizontal drilling and advanced completion techniques offer the potential to make the Pearsall meaningful to us. The commercial viability of the Eagleford shale is unknown and we will monitor the drilling and development
Index to Financial Statements
efforts of other operators before we commit drilling dollars to development. Our acreage is held by production and therefore, we have no pending lease obligations or expirations.
Driscoll Field (also discussed above) - The field was owned by Conoco for much of its life and little development occurred over the last 20 years. We own nearly all of the working interest in this field. We hold 12,000 gross and 11,760 net acres. In 2008, we initiated a field-wide and regional study, which has been deferred due to our expanded activities in other areas. Initial reviews identified several re-engineering and recompletion projects. We successfully completed certain nominal re-engineering and recompletion projects. The acreage is held by production and therefore, we have no pending lease obligations or expirations.
East Nesson Bakken Area - Located in Mountrail County, North Dakota. We have varying working interests in the area ranging from 10% to 15% and net revenue interests ranging from 8.2% to 12.3% in approximately 35,000 acres. This is a developing Bakken Formation horizontal drilling play at vertical depths of about 9,800 feet. We are participating in an active leasehold acquisition and drilling program in a joint venture with another Williston Basin operator. The leasehold generally consists of portions of tracts or governmental subdivisions that will become drilling and spacing units. Accordingly, our working and net revenue interests could be reduced proportionally to acreage contributed to a drilling unit. To date, 13 joint venture wells have been drilled by the operator and 43 wells have been staked by other operators where we own minor interests. The joint venture remains active and has continued to acquire attractive acreage. The reduction in commodity prices which occurred 2008 has caused numerous operators to curtail or significantly reduce drilling and development operations. We expect to continue drilling throughout 2009 with one rig. However, in the near term, until drilling and development costs decline further, wells may include acreage where the joint venture has lower working interests in order to reduce near term capital expenditures. To date, the joint venture gross completed well costs have been approximately $5 million per well. In the near term, we expect gross joint venture wells to be approximately $4.5 million and to average under $4.0 million in four to six months. We intend to further increase our acreage position and participating interest as the play develops and expands.
Eloi Bay Field Complex (also discussed above) - In addition to the proved production, this field has numerous behind-pipe opportunities due to multiple stacked sand reservoirs along with four proved undeveloped locations, which are above existing production. At present, 8,074 gross and 4,352 net acres are held by production. Other operators have had drilling success and established deeper production in the area and we have budgeted funds for the acquisition and reprocessing of 3-D seismic over the field and certain surrounding acreage to define prospective opportunities which may exist. The hurricanes of 2008 and the reduction in commodity prices have caused us to defer data acquisition, processing and interpretation activities. We intend to pursue prospect leads in the orderly course of business. This acreage is held by production and, therefore, we have no pending lease obligations or expirations.
Harris Field (also discussed above) - This field consists of 160 gross and 122 net acres and is in the early stages of water-flooding with one injector well installed in 2007. Additional capital was allocated in 2008 for a crestal well, but has been deferred in favor of committing drilling dollars to projects with lease obligations.
Giddings Field (also discussed above) - We have implemented a development program and we are actively acquiring additional acreage. Along with our affiliated partnership, we control 50,080 gross (46,189 net) acres that are held by production and an additional 11,253 gross and 9,011 net leased acres that are not currently held by production. This field consists of multiple wells that have the potential for production rate increases through the use of fracture stimulations and 11 proved undeveloped drilling locations. We have drilled 10 wells to date and achieved a 100% success rate. We have recently leased 5,683 federal acres. We presently expect at least 15 additional drilling locations and intend to retain the current drilling rig and spud a new well approximately every 60-75 days. We will consider deploying a second rig as drilling costs decline. We are the operator of all of these wells and hold a direct 7.2% working interest in the core development area of this field. In addition, an affiliated partnership owns an 82.8% working interest. Throughout the field we have an average working interest of 6.7% and an incremental reversionary interest of 35.66% through our affiliate partnership (see “Partnership Reserves” above). There has been significant exploration activity in regional proximity to our large acreage position in Grimes County, Texas, including a shallow Yegua formation gas discovery, which we believe would be prospective to our acreage and justify a 3-D seismic program, and in the deeper Eagleford shale which underlies the Austin Chalk. The Eagleford shale is being drilled and evaluated by a number of substantially larger independents.
Index to Financial Statements Landa West Madison Unit (also discussed above) - We hold 1,145 gross and 1,070 net acres in the field. These acres are held by production. This unit has additional potential in reconfiguring its current injection pattern to increase recoveries.
MAK Field (also discussed above) - We hold 3,680 gross and 3,348 net acres by production. A completed waterflood is in place and production has continued to increase slowly over time. The possibility of drilling infill locations in this existing waterflood is under evaluation with at least one location expected in 2009.
New Mexico Fields (also discussed above) - We hold 2,156 gross and 1,847 net acres by production. These acres are held by production. Upside exists in each of the three fields, which are in various stages of waterflood redevelopment. The fields are being studied for additional injection wells and infill producers, which we believe could enhance the waterflood upside.
Northeast Landa Field (also discussed above) - Located in Bottineau County, North Dakota, the field has produced primarily from the Mission Canyon Formation at depths of approximately 3,070 feet-3,100 feet. We hold 1,127 gross and 849 net acres. Cumulative primary recovery to date is approximately 591,000 barrels of oil. Seven gross wells remain on production. This secondary recovery potential has been studied and confirmed for the eastern lobe in the Mission Canyon member of the Madison Formation. Upon recognizing the potential and extent of the floodable reservoir, we launched a leasehold and production acquisition effort to enhance our position in the field. This effort has been successful and is continuing. We have completed preliminary flood designs, but due to questions raised by certain working interest owners we were unable to voluntarily unitize the field in 2008. In the fourth quarter of 2008, we drilled a key evaluation well to collect electric logs and cores for additional evidence. Core analysis and laboratory results should be available in the second quarter of 2009. At that time, we intend to commence unitization proceedings. We expect to have the field unitized and begin water-flood installation in 2009.
Odem Field (also discussed above) - We hold 6,500 gross and 3,250 net acres by production from multiple Frio Sands. We believe numerous proved and non-proved behind-pipe zones exist for recompletion into shallower Frio intervals. We have 3-D seismic data over the properties. Certain wells that were budgeted for 2008 have been deferred in favor of other opportunities.
Oklahoma - During 2008, Catena, a wholly-owned subsidiary of the Company, participated in the formation of an affiliated partnership in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. We directly purchased 18% of the interests, while the partnership purchased the remaining 82%. We believe we can exploit exploration and development opportunities associated with the acreage and in acres in close proximity to those acquired. Lower gas prices and increased differentials have reduced gas prices in many mid-continent areas to less than $3.00 per Mcf and accordingly, drilling economics have been adversely impacted. The undeveloped acreage includes approximately 100 drilling locations. Most of these locations are held by production and therefore do not have expiring lease terms. However, if the combination of high drilling and development and low prices continues this will cause us to defer or even abandon these potential drilling projects. We are high-grading drilling locations and have scheduled the drilling of the first five wells. Additional drilling is expected to be scheduled as prices stabilize and drilling costs decline. The Olson 1-21, was recently drilled and completed in Roger Mills County to an approximate total depth of 13,800 feet. We have a 26.67% working interest in this new productive well.
Quarantine Bay Field (also discussed above) - Including 939 gross and 329 net acres acquired in January 2009, we hold 14,535 gross and 1,281 net acres above 10,500 feet and 5,214 net acres below that depth. Upside in this field consists of numerous behind-pipe opportunities due to the multiple stacked sand reservoirs, along with proved undeveloped and rate acceleration locations in the section above 10,500 feet. In addition, we believe deeper exploration potential exists. We have a 33% working interest in the field, with a 24.75% net revenue interest below 10,500 feet. In cooperation with the operator, we acquired 35 square miles of 3-D seismic data to image and define prospect leads primarily below 10,500 feet. Schlumberger was engaged to reprocess the 3-D seismic data and provide initial interpretive geological and geophysical services. Geophysical and subsurface evaluation is continuing and we have isolated several prospects, the majority of which are on acreage that is held by production operations. At least one exploration well with multiple objectives below 10,500 feet is expected to be drilled in 2009, pending commodity prices and estimated drilling costs.
Index to Financial Statements RipRap Coulee Field - This field is a Bakken Shale play in eastern Montana. It involves horizontal drilling at vertical depths of about 10,000 feet. Currently, we own 997 gross and 498 net leasehold acres in this prospect.
Roth-Leonard Fields - These fields are located in Bottineau County, North Dakota. The fields produce from the same Mississippian Madison stratigraphic porosity as the Sherman and Wayne Fields and have similar water production and pressure histories indicating that they are also horizontal infill drilling candidates (see “Sherman/Wayne Fields” below). We hold 1,374 gross and 1,353 net acres. We have a 100% working interest and 84.9% net revenue interest.
Sherman/Wayne Fields (also discussed above) - We hold 1,090 gross and 967 net acres and operate the field. All of the wells are on rod pump with seven of the wells being horizontal producers. Upside, in this field, consists of two proved undeveloped horizontal infill locations. We drilled two horizontal locations in 2008 and established commercial production. Further upside potential from horizontal drilling could result if we are able to unitize acreage with adjacent leases.
St. Martinville Field (also discussed above) - The field has produced over 14 million barrels of oil at depths ranging from 3,000 feet to 9,500 feet since its discovery several decades ago, and has not been evaluated with a modern 3-D survey. We hold 1,322 gross and 1,283 net acres in the field. A successful well was drilled in late 2005 to a depth of 4,700 feet that initially flowed over 100 Bbls/d, is still producing 30 Bbls/d and has several behind-pipe zones. One additional well is presently budgeted. A 3-D seismic survey is in process with interpretation to begin in the second half of 2009.
Starbuck and Southwest Starbuck Fields (also discussed above) - The Starbuck field was unitized effective November 1, 2007, and includes 6,619 gross and 6,354 net acres. We immediately began our waterflood installation and have a 96% working interest and 83% net revenue interest. Phase one, including four injection wells, water plant and flow lines, was completed in early 2008, when initial water injection began. As a result of the recent increase in the Starbuck Madison Unit production, which is believed to be initial secondary recovery response, phase two of the three phase capital plan was initiated and completed in March 2009. Using our base case, we estimate 1.4 million Bbls recoverable with a development cost of approximately $4.00 to $5.00 per barrel. Recoverable reserve estimates range from 1.0 million Bbls to 2.4 million Bbls. The flood design includes two productive zones, the Midale (Mississippian Charles) and the Berentson (Mississippian Charles B-1) zone, which are being flooded separately. The Starbuck Midale has produced 584,000 barrels of oil and the Berentson has produced 754,000 barrels on primary recovery, for total field production of 1,267,000 barrels of oil. Fourteen gross wells are still producing. The flood installation has been designed to capture and accelerate recovery of existing primary reserves, as well as capture incremental water flood reserves. At the adjacent Southwest Starbuck Field, we have completed Phase One of the water flood plan which included drilling one injection well and installing a water plant and flow lines. Initial water injection commenced in mid-January, 2009. The plant and flow lines will also serve the south end of the Starbuck Madison Unit. The initial flood design includes 560 gross acres where we have a 97.52% working interest and a 75.42% net revenue interest. We estimate that an incremental 170,000 Bbls are recoverable, net to our interest.
Title to Properties
It is customary in the oil and gas industry to make a limited review of title to undeveloped oil and gas leases at the time they are acquired. It is also customary to obtain more extensive title examinations prior to the commencement of drilling operations on undeveloped leases or prior to the acquisition of producing oil and gas properties. With respect to the future acquisition of both undeveloped and proved properties, we plan to conduct title examinations on such properties in a manner consistent with industry and banking practices. We have obtained title opinions, title reports or otherwise conducted title investigations covering substantially all of our producing properties and believe we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, overriding royalty interests, and other burdens which we believe do not materially interfere with the use or affect the value of such properties. Substantially all of our oil and gas properties are and may continue to be mortgaged to secure borrowings under bank credit facilities (see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources”).
Index to Financial Statements
Item 3.
Item 3. Legal Proceedings
We are not party to, nor any of our properties subject to, any material pending legal proceedings. We know of no material legal proceedings contemplated or threatened against us.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Our Annual Meeting of Stockholders was held on October 30, 2008. The items of business noticed and transacted at the meeting were:
•
The election of seven nominees to serve on our Board of Directors and until our next Annual Meeting of Stockholders.
The vote tabulation with respect to each nominee was as follows:
Shares
Voted For
Shares
Withheld
Frank A. Lodzinski
15,058,749
185,985
Collis P. Chandler, III
15,056,749
187,985
Christopher W. Hunt
14,940,202
304,532
Jay F. Joliat
14,744,860
499,874
Scott R. Stevens
14,752,023
492,711
Michael A. Vlasic
15,059,749
184,985
Nicholas L. Voller
15,050,414
194,320
Each nominee was elected to continue to serve on our Board of Directors. There were not any solicitations in opposition to our nominees.
Index to Financial Statements PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock trades on the NASDAQ Global Market under the Symbol “GEOI.” The following tables set forth for the period indicated the low and high trade prices for our common stock as reported by the NASDAQ Capital Market. These trade prices may represent prices between dealers and do not include retail markup, markdowns or commissions.
As of March 20, 2009, there were approximately 600 holders of record of our common stock. We believe that there are also approximately 3,000 additional beneficial owners of our common stock held in “street name.”
Dividend Policy
Amounts shown in our historical financial statements as stockholder distributions in 2006 and 2007 are comprised of distributions by Southern Bay to its partners.
We have never paid dividends on our common stock and do not intend to pay a dividend in the foreseeable future. Furthermore, our amended credit agreement with our bank restricts the payment of cash dividends. The payment of cash future dividends on common stock, if any, will be reviewed periodically by our Board of Directors and will depend upon, among other things, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions imposed by our present or future bank credit arrangements.
Index to Financial Statements Equity Compensation Plan Information
The following sets forth information as of March 25, 2009, concerning our compensation plan under which shares of our common stock are authorized for issuance.
In 2007, employee options exercised totaled 35,208 shares at $2.37 and 40,500 shares at $2.31. There were not any employee options exercised during 2008.
Index to Financial Statements
Item 6.
Item 6. Selected Financial Data
(1) The 2006 consolidated financial statements were those of Southern Bay, which, as a partnership, was generally not subject to federal and state income taxes.
Index to Financial Statements
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations
The following discussion should be read in conjunction with the consolidated financial statements and related notes thereto reflected in the index to the consolidated financial statements in this report.
Merger - Change in Management, Control and Business Strategy
As discussed elsewhere in this report, we underwent a substantial change in ownership, management, voting control, assets and business strategy as a result of the acquisition of Southern Bay and Chandler (via the Merger) and a purchase of working interests in a Chandler-operated project, which closed in April 2007. For financial reporting purposes, the Merger was accounted for as a reverse acquisition of GeoResources, Inc. by Southern Bay. Therefore, the results of operations and cash flows presented herein for the year ended December 31, 2008, are those attributable to the combined entities. The results of operations and cash flows for the year ended December 31, 2007, are those attributable to the former Southern Bay entity for the entire twelve months and those of the combined entity for the period from April 18, 2007, through December 31, 2007. The results of operations and cash flows for the year ended December 31, 2006, are those attributable to the former Southern Bay entity.
General
We are an independent oil and gas company engaged in the acquisition and development of oil and gas reserves through an active and diversified program which includes purchases of reserves, re-engineering, development, and exploration activities. As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to effectively compete for capital and acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit, and assemble an oil and gas reserve base with a market value exceeding its acquisition, development and production costs.
We continue to implement our business strategy to acquire, discover and develop oil and gas reserves and achieve continued growth. Management continues to focus on reducing operating and administrative costs on a per unit basis. In addition, we have attempted to mitigate downward price volatility by the use of commodity price hedging. The current volatile price environment for oil and natural gas is significant, and management cannot predict the prices that will be available during the life of our current business plan. Following is a brief outline of our current plans:
•
Acquire oil and gas properties with significant producing reserves and development and exploration potential;
•
Solicit industry partners in acquisitions, on a promoted basis, in order to diversify, reduce average cost and generate operating fees;
•
Implement re-engineering and development programs within existing fields;
•
Pursue exploration projects and increase direct participation in projects over time. Solicit industry partners, on a promoted basis, for internally generated projects;
•
Selectively divest assets to upgrade our producing property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus on existing fields and new projects with greater development and exploitation potential;
•
Continue activities directed toward reducing per-unit operating and general and administrative costs on a long-term sustained basis; and
•
Obtain additional capital through the issuance of equity securities and/or through debt financing.
While the impact and success of our corporate plans cannot be predicted with accuracy, our goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return.
In addition to our fundamental business strategy, we intend to actively pursue corporate acquisitions and mergers. Management believes that opportunities may become available to acquire corporate entities or otherwise effect business combinations, particularly as a result of recent lower commodity prices and the contraction in equity and debt financing markets. We intend to consider any such opportunities which may become available and are beneficial to stockholders. The primary financial considerations in the evaluation of any such potential transactions
Index to Financial Statements
include, but are not limited to: (1) the ability of small cap oil and gas companies to gain recognition and favor in the public markets; (2) share appreciation potential; (3) shareholder liquidity; and (4) capital formation and cost of capital to effect growth.
Recent Property Acquisitions and Divestitures
During 2008, we expanded our acreage positions and drilling inventory, implemented our drilling programs, and began the process of high-grading the assets resulting from the Merger and significant acquisitions of 2007. We sold or abandoned certain properties which, collectively had net production at the time of sale of 316 Bbls/d and 742 Mcfe/d, but were outside our focus areas, had limited development potential, short remaining productive lives, high maintenance requirements or significant plugging and abandonment obligations. We also acquired producing and undeveloped properties, principally in the Williston Basin and in Oklahoma. A summary of this activity is as follows:
•
In January, 2008, we sold all of our interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was sold to an unaffiliated party for $6.6 million in cash. At the date of sale, the carrying value of this property was equal the sales price; therefore, no gain or loss was recognized on the sale.
•
In February, 2008, we acquired producing properties from an unaffiliated party in the Williston Basin of North Dakota and Montana for $7.9 million cash. The acquired properties are operated by us.
•
In February, 2008, we sold our interests in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million and recognized gains of $430,000.
•
In May, 2008, we sold seven non-core fields in Louisiana and Texas for approximately $11.8 million. We recognized a net gain of $1.5 million related to these sales.
•
In May, 2008, Catena Oil & Gas LLC (“Catena”), a wholly-owned subsidiary, participated in the formation of OKLA Energy Partners LP (“OKLA”) in order to acquire certain producing oil and gas properties and undeveloped acreage located throughout Oklahoma. The acquisition totaled $61.7 million. Catena directly purchased 18% of the interests and OKLA purchased the remaining 82%. Catena, the general partner for OKLA, has a 2% partnership interest. Under the terms of the partnership agreement, Catena’s general partner interest can increase to approximately 36% pending certain performance hurdles.
•
In September, 2008, we acquired producing properties in Oklahoma from an unaffiliated party for $3.6 million in cash.
•
During 2008, we identified an exploration opportunity in the Paradox Basin and began leasing in Colorado and Utah targeting the Gothic shale as a newly emerging resource play with multiple objectives. In the fourth quarter of 2008, we sold a majority of our interest for $6 million and recognized a gain of $2.5 million. We retained an option to participate, up to a 12.5% working interest, in any future drilling on the acreage.
Index to Financial Statements Results of Operations
Year ended December 31, 2008, compared to the year ended December 31, 2007.
We recorded net income of $13,522,000 and $3,069,000 for the years ended December 31, 2008, and 2007, respectively. The $10,453,000 increase in net income resulted primarily from the following factors.
The following discussion applies to the above changes.
Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $48,745,000, or 133%. Properties acquired from AROC Energy LP in October 2007, accounted for approximately $41,182,000 of the increase. The remaining $7,563,000 increase resulted primarily from an increase in commodity prices and increase in production volumes. Price and production comparisons are set forth in the following table. Properties acquired from AROC Energy LP accounted for increased production of approximately 1,063,000 Mcf of gas and approximately 789,000 barrels of oil during 2008.
Lease Operating Expenses. Our lease operating expenses increased from approximately $10,818,000 for the year ended December 31, 2007 to $22,914,000 for 2008, an increase of $12,096,000 or 112%. Properties acquired from AROC Energy LP accounted for $9,146,000 of the increase. On a unit-of-production basis, barrel of oil equivalent (“BOE”) costs increased by $2.32 or 14% as a result of higher costs due to unprecedented demand for personnel, materials, services and rigs caused by high commodity prices during most of 2008.
Index to Financial Statements Re-engineering and workover. Our re-engineering and workover costs increased by $1,426,000 from $2,092,000 in 2007 to $3,518,000 in 2008, due to an increased emphasis on restoring and enhancing existing production capabilities.
Production Taxes. Our production taxes increased by $4,637,000 or 161%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in our various jurisdictions. Our production taxes for 2008 and 2007 were 7.9% and 7.3%, respectively, of oil and gas sales before the effects of hedging. The 2008 rate increased slightly from 2007 mainly due to change in our portfolio of producing properties.
Exploration and Impairment Costs. Our exploration costs were $2,592,000 for the year ended December 31, 2008, and $153,000 for the year ended December 31, 2007. In 2008, we drilled four gross exploratory dry holes with costs incurred through December 31, 2008, of $1,948,000, wrote-off undeveloped properties with a cost of $483,000 and incurred geological costs of $161,000. In 2007, we incurred $153,000 for geological and geophysical data. In 2008, we recorded a non-cash impairment charge of $8,339,000 due to the write-down of proved properties. The book value of these properties exceeded our estimate of future cash flows based on our current view of future commodity prices. We had no impairments in 2007.
General and Administrative Expenses - Our G&A costs increased $655,000 due primarily to overall business expansion as well as increases in salaries and other overhead expenses, partially offset by cost reductions resulting from the centralization of certain job functions.
Depreciation, Depletion and Amortization - The increase in DD&A expenses attributable to the properties acquired from AROC Energy LP was $5,618,000. The remaining increase of $2,882,000 was due to higher DD&A in the fourth quarter of 2008 due to lower reserve estimates at year-end, which was caused by lower commodity prices.
Interest Income and Expense - Interest expense increased by $2,904,000 due to higher average debt levels during the year ended December 31, 2008, compared to 2007. During the first ten months of 2007, the Company had a long-term debt balance of less than $10 million. In October, 2007, the Company borrowed $96 million in conjunction with the AROC Energy LP acquisition. During 2008, the Company paid down this balance to $40 million. Interest income decreased by $379,000 during the year ended December 31, 2008, compared to 2007, due to lower interest rates on average invested cash balances.
Hedge Ineffectiveness. During the year ended December 31, 2008, the gain from hedge ineffectiveness was $123,000, compared to an expense of $287,000 for 2007. In 2008, our derivatives that are accounted for as cash flow hedges increased in value from a net liability to a net asset; therefore, the ineffective portion of these derivatives resulted in a gain on our income statement. In 2007, our derivatives that were accounted for as cash flow hedges decreased in value. Therefore, the ineffective portion of the derivatives resulted in a loss on our income statement.
Loss on Derivative Contracts. In December, 2008, we split up a $50 million notional value interest rate swap that was previously accounted for as a cash flow hedge. The swap was split up into a $10 million swap and $40 million notional amount swap. We continued hedge accounting for the $40 million swap and accounted for the $10 million swap as a trading security. We recognized $563,000 of losses related to this $10 million interest rate swap.
Other Income. Other income increased by $1,812,000 during the year ended December 31, 2008, compared to 2007. The increase resulted from increases in partnership management fees of $756,000, increases in partnership income of $877,000 and increases in property operating income of $179,000. Additionally, during 2008, we sold a number of non-core properties and recognized a gain of $4,362,000 versus gains of only $49,000 in 2007.
Income Tax Expense. Our provision for income taxes for the year ended December 31, 2008, was $7,769,000 compared to $4,880,000 for 2007. Our income tax expense increased significantly as a result of higher pre-tax earnings. Our effective tax rate for 2008 was approximately 36.5%. Our effective tax rate for 2007, after
Index to Financial Statements
excluding a non-recurring charge of $2,214,000, was approximately 34%. As previously stated, the 2006 consolidated financial statements, as presented herein, are those of Southern Bay which, as a partnership, was generally not subject to federal and state income taxes. Deferred income tax expense for 2007 included a non-recurring charge of $2,214,000. GAAP requires that when an entity’s tax status changes from non-taxable to taxable, the deferred taxes related to differences in the GAAP basis of net assets and their tax basis, be recognized in the period of that change in status. The increase in our effective tax rate from year to year was due to a 1% increase in our federal rate as well as the additional income from our Northern Region which is taxable at the state level.
Year ended December 31, 2007, compared to the year ended December 31, 2006.
We recorded net income of $3,069,000 and $4,247,000 for the years ended December 31, 2007, and 2006, respectively. The $1,178,000 decrease in net income resulted primarily from the following factors:
Net revenues from oil and gas sales increase $22,540,000, or 161%. Properties acquired in the AROC acquisition accounted for $11,043,000 of this increase and the Merger accounted for $8,066,000 of the increase. Higher prices, as well as the acquisition and development of properties during the year, accounted for the remaining increase of $3,431,000. Properties acquired in the AROC acquisition accounted for increased production of approximately 374,000 Mcf of gas and approximately 91,000 barrels of oil. Properties acquired in the Merger accounted for increased production of approximately 244,000 Mcf of gas and approximately 105,000 barrels of oil. Prices and production comparisons are set forth in the following table.
Lease Operating Expenses, Workover Costs and Production Taxes. Our lease operating expenses and workover costs increased $8,274,000. This increase was due primarily to properties acquired in the AROC acquisition and properties acquired in the Merger. On a unit-of-production basis, BOE costs increase 18%. The
Index to Financial Statements
increase was a result of the acquisition and development of oil and gas properties in 2007 and a high demand for personnel, materials, services and rigs caused by high commodity prices. On a BOE basis, production volumes increase 138%. Accordingly, lease operating expenses increased primarily as a result of additional production volumes attributable to the AROC acquisition and to the Merger. Due to increased production volumes and increased revenues, production taxes increased by $1,814,000 or 170%.
Exploration Costs. Exploration costs were $153,000 for the year ended December 31, 2007, and $558,000 for the year ended December 31, 2006. We drilled two unsuccessful exploratory wells in 2006 and none in 2007, but we spent $153,000 for geological and geophysical data in 2007.
General and Administrative Expenses. General and administrative costs increased $3,709,000 due primarily to non-recurring costs associated with the Merger and consulting fees associated with the Merger and consulting fees associated with compliance with the Sarbanes-Oxley Act, as well as to overall business expansion related to the Merger. Expenses associated with the Merger included bonus and stock-based compensation totaling $524,000, legal, accounting and proxy services of $295,000; and a NASDAQ listing fee of $95,000 for entry into the National Global Market. In 2007, we also incurred fees and costs of $264,000 in connection with readiness for Sarbanes-Oxley compliance.
Depreciation, Depletion and Amortization. The increase in DD&A expense attributable to the properties acquired in the Merger was $1,215,000. The remaining increase of $2,910,000 was due to the AROC acquisition, as well as property acquisitions by Southern Bay prior to the Merger, partially offset by lower net capitalized costs on other properties.
Interest Income and Expense. Interest expense increased by $1,628,000 due to high debt levels in 2007. In October, 2007, we borrowed $96 million to acquire the limited partner interest in the AROC acquisition. Interest on that debt was $1,436,000 in 2007. Interest income increased $79,000 due to larger invested cash balances in 2007, as well as interest on notes receivable arising from the sale of non-core properties and equipment in 2007.
Hedge Ineffectiveness. For 2007, loss from hedge ineffectiveness was $287,000 compared to a gain of $393,000 for 2006. This difference of $680,000 resulted from an increase in the liability associated with the mark-to-market valuation of our hedge contracts. This increase was due to additional hedging in the fourth quarter of 2007, as well as to higher product prices in 2007 and continuing into 2008.
Other Income. Other income, net of other expenses, increased by $977,000. This increase was due to higher property operating income in 2007, partially offset by non-recurring income in 2006 resulting from reductions in contingent liabilities and allowance for bad debts.
Income Tax Expense. Income tax expense for 2007 was $4,880,000 compared to $33,000 for 2006. As previously stated, the 2006 consolidated financial statements as presented herein are those of Southern Bay, which as a partnership, was generally not subject to federal and state income taxes. The small amount reflected as income tax expense for 2006 represents a Texas margin tax which was calculated using gross revenue less certain deductions and was further reduced to reflect the percent of business derived from Texas. This tax is require by GAAP to be accounted for as an income tax at the entity level. In addition, deferred income tax expense for 2007 included a non-recurring charge of $2,214,000. GAAP requires that when an entity’s tax status changes from non-taxable to taxable, the deferred taxes related to differences in the GAAP basis of net assets and their tax basis, be recognized in the period of that change in status.
Hedging Activities
In an attempt to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing, we have and will likely continue to enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. The following is a summary of our current oil and gas hedge contracts.
Index to Financial Statements The fair market value of the hedge contracts in place at December 31, 2008, was an asset of $14,609,000, of which $8,200,000 was classified as a current asset and $6,409,000 was classified as a long-term asset. Realized hedge settlements included in oil and gas revenues were costs of $9,970,000 and $2,910,000 for the years ended December 31, 2008, and 2007, respectively. Due to hedge ineffectiveness on these hedge contracts during the years ended December 31, 2008, and 2007, we recognized a gain of $123,000 and a loss of $287,000, respectively.
Based on the estimated fair market value of our derivatives, designated as hedges at December 31, 2008, we expect to reclassify net gains on commodity derivatives of $8.2 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
At December 31, 2008, a 10% change in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to increase by $10 to $12 million or decrease by $8 to $10 million with similar increases or decreases in other comprehensive income (loss) included in stockholders’ equity in the balance sheet. Since we have designated all of our commodity derivative instruments as cash flow hedges and therefore the change in market value of the effective portion of the hedge is included in other comprehensive income, a 10% change in fair value would not have a significant effect on net income. However, if our hedges did not qualify for hedge accounting treatment, our net income for 2008 would have increased by $20.5 million.
Additionally, should commodity prices increase or decrease in the future periods by 10%, our realized settlement gains (losses) on commodity derivatives, which are included in oil and gas revenues, would increase or decrease by approximately $3 to $4 million in 2009.
In connection with the borrowing from our bank to fund the October, 2007, AROC acquisition, we also entered into a two-year interest rate swap contract on $50 million of the debt, to protect us against interest rate increases. During 2008, we extended the term of this interest rate swap through October, 2010, and broke the swap up into two pieces, a $40 million swap and a $10 million swap. We account for the $40 million swap as a cash flow hedge while the $10 million swap is accounted for as a trading security. The value of these swaps is a liability of $2,817,000 of which $1,572,000 is classified as a current liability. We also recognized a loss of $563,000 on the $10 million swap.
Index to Financial Statements Based on the estimated fair market value of our derivatives designated as hedges at December 31, 2008, we expect to reclassify net losses on our $40 million interest rate swap derivative of $1.3 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlements may differ materially.
We do not engage in speculative trading activities and do not hedge all available or anticipated quantities of our production. In implementing our hedging strategy we seek to:
•
Effectively manage cash flow to minimize price volatility and generate internal funds available for capital development projects and additional acquisitions;
•
Ensure our ability to support our exploration activities as well as administrative and debt service obligation; and
•
Allow certain quantities to float, particularly in months with historically increased price potential.
We believe that speculation and trading activities are inappropriate for us, but also that management of realized prices is a necessary part of our strategy.
Estimating the fair value of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices, which although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of our commodity hedges. We currently obtain fair value positions from our counterparties and compare that value to our internally calculated value. Our practice of comparing our value to that of our counterparties, who are more specialized and knowledgeable in preparing these complex calculations, reduces our risk of error and approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the cost to us to terminate a contract at that point in time.
Administrative and Operating Costs
On an ongoing basis, we focus on cost-containment efforts related to administrative and operating costs. However, we must continue to attract and retain competent management, technical and administrative personnel to successfully pursue our business strategy and fulfill our contractual obligations.
Liquidity and Capital Resources
We expect to finance future acquisition, development and exploration activities through working capital, cash flows from operating activities, our bank credit facility, sale of non-strategic assets, various means of corporate and project finance and possibly through issuance of additional securities. In addition, we intend to continue to partially finance our drilling activities through the sale of participations to industry or institutional partners on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs. Financing activities during 2008 have resulted in a net reduction of debt of $56 million from the outstanding debt of $96 million at December 31, 2007. During 2007, we borrowed an additional $3 million, assumed $1.8 million of debt in the Merger, and repaid the entire balance outstanding of our bank debt of $9.8 million in late June, 2007. In October, 2007, we borrowed $96 million to finance the AROC Energy LP acquisition. During the first quarter of 2008, we repaid $10 million in debt using cash flows from operations. During the second quarter, we completed a private placement of common stock and warrants to acquire common stock and used the net proceeds of $32 million plus cash flows from operations to reduce our debt by an additional $36 million. In the fourth quarter, we repaid $10 million in debt using cash flows from operations.
Index to Financial Statements
(1) The amount shown as stockholder distributions in 2007 and 2006 are comprised of distributions by Southern Bay to its partners prior to the Merger.
Credit Facility
At December 31, 2008, we had a $100 million borrowing base, with available borrowing capacity of $60 million in accordance with our Amended Credit Agreement with our bank. The borrowing base is redetermined in October and April of each year. On March 13, 2009, in connection with the borrowing base redertermination for April 2009, the Company was advised by its lead bank that it will recommend that the $100 million borrowing base be extended to the next redetermination. Approval is required by the bank group and its presently expected in early April.
Cash Flows From Operating Activities
For 2008, net cash provided by operating activities was $42.3 million, up $21.5 million from 2007. This increase was directly attributable to the increase in production resulting from acquisition and development activities and increases in oil and gas prices, partially offset by increased general and administrative expense associated with operating a larger company.
Cash Flows From Investing Activities
Cash applied to oil and gas capital expenditures was $51.8 million for 2008, $110.1 million for 2007, and $14.7 million for 2006. In 2008, we realized cash of $26.8 million from the sale of non-core properties. In 2007, we collected $2.4 million from the sale of non-core properties. During 2008, we invested $978,000 in a newly formed oil and gas limited partnership for which we are the general partner. In 2007, we invested $1.6 million in a different oil and gas limited partnership for which we are also the general partner.
Capital Budget
In early 2008, we developed and reported a two year capital budget totaling $61.5 million. As the year progressed we expanded our portfolio of projects, including both new and expanded projects. The projects were also modified based on performance and the effects of our acquisition and divestiture activities. The overall regional focus and profile of our portfolio remained consistent with our business strategy. In anticipation of increasing our capital spending, commensurate with our then current level of cash flows and profitability due to historically high commodity prices, in the third quarter of 2008, we updated our projected expenditures for the detailed review of our management and Board of Directors. While our intent, at that time, was to formally plan to increase our capital spending, the rapid and significant reductions in commodity prices caused us to re-evaluate and in some cases, re-direct our capital spending. The table below is presented simply to disclose the nature and diversity of opportunities currently in our portfolio. However, considering the current commodity prices, we now expect to return to our original capital budget and spend approximately $60 to $64 million over the course of 2009 and 2010. The remaining $19 to $23 million presented below are for projects that we anticipate undertaking in the near future; however, considering the significant volatility in commodity prices we have not yet set a date certain for
Index to Financial Statements
the projects. These deferred projects are largely held by production and most can be deferred without exposure to lease expiration under present operating conditions. Our current estimate of $60 to $64 million is predicated on prices equal to or better than the NYMEX forward curve, our hedge positions, reasonable success once the projects are undertaken and costs that are consistent with our estimates. However, we are committed to generally limiting our capital spending to the Company’s cash flows, although in certain limited circumstances, we may utilize our borrowing capacity for development or lease saving operations. We absolutely will not use our borrowing capacity for exploratory drilling. Additionally, in the opinion of management, we have sufficient cash flows and liquidity to fulfill all lease obligations.
Inventory of Planned Exploration and Development Projects
Notes:
(1) Continuation of an ongoing horizontal drilling and development program with an affiliated institutional partnership. We believe we can spud a new well every 60-75 days, utilizing one rig for a 3-4 year period. At present, we believe we have at least 15 drilling locations, the majority of which are expected to be dual laterals. The dual lateral configuration reduces the number of wells but also increases reserve recoveries and favorably impacts finding and development costs. In addition, without further significant declines in commodity prices and development costs, we expect to re-enter numerous well bores and extend existing laterals or drill additional laterals. None of the possible reentries are included in the above table as all such opportunities are held by production and have no critical timing. We may consider deploying a second drilling rig as drilling costs come down.
(2) Includes both proved undeveloped and non-proved reserve potential.
(3) Principally South Louisiana and the Texas Gulf Coast.
(4) Includes activities related to existing fields intended to enhance production and lower operating expenses. These expenditures include replacement, repairs or additional flowlines, facilities, and/or compression as well as the modification of the down-hole lift method, recompletions and side-track drilling.
(5) Potential expenditures associated with further expansion of acreage and prospect inventory generally within close proximity of our existing fields.
(6) Includes eight horizontal development wells or additional lateral wells within existing fields where we have interests ranging from 66% to 100%.
(7) Includes 20 wells operated by our joint venture partner where our working interest may range from 4% to 10%. This participating working interest varies based on acreage contributed to the approved drilling units. It also includes numerous wells where our working interest is 1% or less. While not material financially, management has generally elected to participate in all such drilling within our focus area primarily to collect valuable technical data related to the drilling operations and reservoir characteristics. Also, it includes one Bakken Shale test well in Montana that we presently hold a 50% working interest.
Index to Financial Statements The table above does not include all contemplated projects or inventory in our portfolio but is representative of the bulk of such activities. In summary, our drilling and development activities include diversified opportunities intended to develop reserves and increase production. The current exploration and development schedule presented in the table above includes (i) 32 wells which have assigned proved undeveloped reserves and the potential for the development of non-proved reserves (excluding numerous smaller non-operated interest which may be developed); (ii) seven exploratory test wells including two potentially high impact exploratory wells at Quarantine Bay, Plaquemines Parish, Louisiana; (iii) 20 Bakken Shale wells (excluding minor non-operated interests); (iv) water flood installation and expansion opportunities; and (v) seismic and acreage expenditures intended to further expand our portfolio.
The budget, as well as the timing of expenditures, is subject to change as we re-evaluate alternative projects and further expand our portfolio. Further, because much of our opportunity is held by production we may shift our expenditures between regions and projects (such as development versus exploration) in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs. Furthermore, our budget may be accelerated or deferred, pending commodity prices, drilling and service rig availability and cost and adequate staffing to effectively manage activities and control costs. Finally, certain expenditures may be deferred in favor of new opportunities.
We believe projected expenditures will result in increased production, cash flows and reserve value and will further expose us to potential upside from exploration. We further believe any deferral of certain projects will not result in any material loss. Should we be unable to acquire new properties, capital expenditures associated with existing properties could be increased.
New Accounting Standards
On December 31, 2008, the SEC published the revised rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in existing oil and gas rules to make them consistent with the petroleum resources management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology to determine reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determining reserves. The pricing to be used in determining reserves is a 12-month average price. We are required to comply with the amended disclosure requirement for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.
In March, 2008, the FASB issued Statement No. 161, Disclosure about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133 (“SFAS 161”). The adoption of SFAS 161 is not expected to have an impact our consolidated financial statements, other than additional disclosures. SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.
In December, 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51 (“SFAS 160”). This statement amends ARB No. 51 and intends to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards on the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. SFAS 160 is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The Company does not believe that this statement will have a material impact on its consolidated financial statements.
In December, 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R may have an impact on our consolidated financial statements when effective, but the nature and magnitude of
Index to Financial Statements
the specific effects will depend upon the nature, terms, and size of the acquisitions that we consummate after the effective date. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company intends to adopt SFAS 141R effective January 1, 2009, and apply its provisions prospectively.
In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). This new standard permits an entity to make an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS 159 was effective as of the beginning of the first fiscal year beginning after November 15, 2007. We elected not to adopt the fair value option provision allowed under SFAS 159.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in Note A to our consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Gas Properties
We use the successful efforts method of accounting for oil and gas operations. Under this method, costs to acquire oil and gas properties, drill successful exploratory wells, drill and equip development wells, and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells, geological, geophysical as well as cost of carrying and retaining unproved properties are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”) of the capitalized costs associated with proved oil and gas properties are computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Oil and gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Long-lived assets committed by management for disposal are accounted for at the lower of cost or fair value, less cost to sell. All of our properties are located within the continental United States and the Gulf of Mexico.
Oil and Natural Gas Reserve Quantities
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, and asset retirement obligations. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
•
The quality and quantity of available data;
Index to Financial Statements
•
The interpretation of that data;
•
The accuracy of various mandated economic assumptions; and
•
The judgments of the persons preparing the estimates.
Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, Cawley, Gillespie & Associates, Inc. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of December 31, 2008. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.
Depreciation, Depletion and Amortization (“DD&A”)
Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Impairment of Oil and Gas Properties
We review the value of our oil and gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based on expected future flows using discounted rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making. Different pricing assumptions or discount rates could result in a different calculated impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
Asset Retirement Obligation
Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas field.
Derivative Instruments and Hedging Activity
We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We use hedging to help ensure that we have adequate cash flows to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based, in part, on our view of current and future market
Index to Financial Statements
conditions. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We primarily utilize swaps and costless collars, which are placed with major financial institutions. The oil and natural gas reference prices of these commodity derivative contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive. All derivative instruments are recorded on the consolidated balance sheet at fair value. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the fair value gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective and is reclassified to gain (loss) on oil and natural gas hedging activities line item in our consolidated statements of income in the period that the hedged production is delivered. Hedge effectiveness is measured quarterly based on the relative changes in the fair value between the derivative contract and the hedged item over time.
Our costless collars are valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index. Our swaps are valued based on a discounted future cash flow model. Our primary input for the model is the NYMEX futures index. Our model is validated by the counterparty’s marked-to-market statements. The discount rate used in determining the fair values of these instruments includes a measure of nonperformance risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Our results of operations each period can be impacted by our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control. If our derivative contracts would not qualify for cash flow hedge treatment, then our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments, as our contracts are marked to their period end market values.
The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging relationship and on a periodic basis as appropriate.
Income Taxes and Uncertain Tax Positions
We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 (“FIN 48”), which requires income tax positions to meet a more-likely-than-not recognition threshold to be recognized in the financial statements. Under FIN 48, tax positions that previously failed to meet the more-likely-than-not threshold should be recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. Prior to 2007, we recorded contingent income tax liabilities to the extent they were probable and could be reasonably estimated. We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be.
Index to Financial Statements Revenue Recognition
We predominantly derive our revenue from the sale of produced oil and gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.
Accounting for Business Combinations
Our business has grown substantially through acquisitions, and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations to date using the purchase method, which is the only method permitted under SFAS No. 141, Business Combinations, and involves the use of significant judgment.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Effects of Inflation and Pricing
We experienced increased costs during 2008, 2007 and 2006 due to increased demand for oil field products and services. The oil and gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, special purpose entities, financing partnerships or guarantees.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from changes in commodity prices. In the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements. We do not participate in these transactions for trading or speculative purposes. While the use of these arrangements limits the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements.
Index to Financial Statements The following is a list of contracts outstanding at December 31, 2008:
Item 8.
Item 8. Financial Statements and Supplementary Data
See “Index to Consolidated Financial Statements and Supplementary Information” of Page.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None.
Index to Financial Statements
Item 9A(T).
Item 9A(T). Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer have implemented, or caused to be implemented, our disclosure controls and procedures to ensure that material information relating to the Company is communicated adequately to our Chief Executive Officer and our Chief Financial Officer through the end of the reporting period addressed by this report. As of the end of the reporting period reflected herein, our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures, and based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this report, are effective in alerting them on a timely basis to material information relating to the Company that is required to be included in our reports filed or submitted under the Securities Exchange Act of 1934.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended). Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the our financial statements for external purposes in accordance with the U.S. GAAP.
While we believe that our existing internal control framework and procedures over financial reporting have been effective in accomplishing our objectives, we intend to continue the practice of reevaluating, refining, and expanding its internal controls over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, our management used criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Based on our assessment, we believe that, as of December 31, 2008, our internal control over financial reporting is effective based on those criteria. This report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this report.
Changes in Internal Control over Financial Reporting
Our management has also evaluated our internal controls over financial reporting, and there have been no significant changes in our internal controls or in other factors that could significantly affect those controls during the quarter ended December 31, 2008.
Item 9B.
Item 9B. Other Information
None.
Index to Financial Statements PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Directors, Executive Officers and Corporate Governance
Information concerning our executive officers and directors is set forth below:
(1) Member of the Executive Committee.
(2) Member of the Audit Committee.
(3) Member of the Nominating Committee.
(4) Member of the Compensation Committee.
Frank A. Lodzinski has been President, Chief Executive Officer and Director of the Company since the Merger on April 17, 2007. He has 38 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates, Inc., which acquired controlling interests in oil and gas properties and limited partnerships. Subsequently, certain assets were sold and in 1992 the partnership interests were exchanged for common shares of Hampton Resources Corporation (NASDAQ: “HPTR”), which Mr. Lodzinski joined as president. In 1995, Hampton was sold to Bellwether Exploration Company. In 1996, he acquired Cliffwood Oil & Gas Corporation and in 1997, Cliffwood shareholders acquired controlling interest in Texoil, Inc. (NASDAQ: “TXLI”), where Mr. Lodzinski served as CEO and president. In 2001, Texoil was sold to Ocean Energy, Inc. Mr. Lodzinski was then appointed CEO and President of AROC, Inc., which was a financially distressed company. He and his management team took the company private, recapitalized the company and implemented a turn-around and liquidation plan. In late 2003, AROC completed an asset monetization, which resulted in a sizable liquidity event for preferred and common shareholders. Mr. Lodzinski subsequently formed Southern Bay Energy, LLC, and in 2005 acquired certain assets from AROC. Mr. Lodzinski is a certified public accountant and holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.
Index to Financial Statements Collis P. Chandler, III has been Executive Vice President and Chief Operating Officer - Northern Region and Director of the Company since the Merger on April 17, 2007. He has been President and sole owner of Chandler Energy, LLC since its inception in July 2000. From 1988 to July 2000, Mr. Chandler served as Vice President of The Chandler Company, a privately-held exploration company operating primarily in the Rocky Mountains. His responsibilities over the 12-year period included involvement in exploration, prospect generation, acquisition, structure and promotion as well as direct responsibility for all land functions including contract compliance, lease acquisition and administration. Mr. Chandler received a Bachelor of Science Degree from the University of Colorado, Boulder, in 1992.
Francis M. Mury has been Executive Vice President and Chief Operating Officer - Southern Region of the Company since the Merger on April 17, 2007. He has been active in the oil and gas industry since 1974. He was employed by AROC Inc. as Executive Vice President from May 2001 through December 2004. Since January 2005, he has been employed by Southern Bay Energy LLC as Executive Vice President. Mr. Mury worked for Texaco, Inc. from July 1974 through March 1979, ending his tenure there as a petroleum field engineer. From April 1979 through December 1985, he worked for Wainoco Oil & Gas as a production engineer and drilling superintendent. From January 1986 to November 1989 he worked for Diasu Oil & Gas as an operations manager. He has worked with Mr. Lodzinski since 1989, including at Hampton Resources Corporation, where he served as Vice President - Operations from January 1992 through May 1995, and Texoil, Inc. where he served as Executive Vice President from November 1997 through February 2001. His experience extends to all facets of petroleum engineering, including reservoir engineering, drilling and production operations and further into petroleum economics, geology, geophysics, land and joint operations. Geographical areas of experience include the Gulf Coast (offshore and onshore), east and west Texas, Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania and Michigan. Mr. Mury received a degree in Computer Science (1974) from Nicholls State University, Thibodeaux, Louisiana.
Robert J. Anderson has been Vice President, Business Development, Acquisitions and Divestitures of the Company since the Merger on April 17, 2007. He is a Petroleum Engineer with 19 years of diversified domestic and international experience with both major oil companies (ARCO International/Vastar Resources) and independent oil companies (Hunt Oil/Huguton Energy/Anadarko Petroleum). From October 2000 through February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum engineer. From March 2004 through December 2004 he was employed by AROC Inc. as Vice President, Acquisitions and Divestitures. He joined Southern Bay Energy, LLC in January 2005 as Vice President, Acquisitions and Divestitures. His professional experience includes acquisition evaluation, reservoir and production engineering and field development, and project economics, budgeting and planning. Mr. Anderson’s domestic acquisition and divestiture experiences include the Gulf Coast of Texas and Louisiana (offshore and onshore), east and west Texas, north Louisiana, Mid-Continent and the Rockies. His international experience includes Canada, South America and Russia. He has an undergraduate degree in Petroleum Engineering from the University of Wyoming (1986) and also holds an MBA, Corporate Finance, from the University of Denver (1988).
Howard E. Ehler has been Vice President and Chief Financial Officer of the Company since the Merger on April 17, 2007. He was employed as Vice President and Chief Financial Officer of AROC Inc. from May 2001 through December 2004. Since January 2005, Mr. Ehler has been employed by Southern Bay Energy, LLC as Vice President and Chief Financial Officer. He previously served as Vice President of Finance and Chief Financial Officer for Midland Resources, Inc. from March 1997 through October 1998. From November 1999 through April 2001 he performed independent accounting and auditing services in oil and gas as a sole practitioner in public accounting. He was employed in public accounting with various firms for over 21 years, including practice with Grant Thornton, where he was admitted to the partnership. He has substantive experience in oil and gas banking, finance, accounting and reporting. In addition, his experience includes partnership administration, tax, budgets and forecasts and cash management. Mr. Ehler holds an Accounting Degree from Texas Tech University (1966) and has been a certified public accountant since 1970.
Christopher W. Hunt has been a Director of the Company since the Merger on April 17, 2007. He has been a founder and president of Knightsbridge Capital, LLC, a private investment firm in Denver, Colorado, since 2002.
Index to Financial Statements
Prior to founding Knightsbridge Capital, Mr. Hunt served as a vice president at the Anschutz Corporation, from 1997 to 2001, where he provided financial, investment and merger and acquisition services for that company’s investment portfolio and served in the Denver and London, England, offices. Previously, Mr. Hunt served in the private investment group of Bechtel Enterprises in San Francisco, California, from 1996 to 1997. Mr. Hunt holds a Bachelor’s Degree from Yale University (1990) and a Master’s Degree in Business from the J. L. Kellogg School of Management at Northwestern University (1995).
Jay F. Joliat has been a Director of the Company since the Merger on April 17, 2007. He has, for more than the past five years, been an independent investor and developer in commercial, industrial and garden style apartment real estate and development, residential home building, restaurant ownership and management, as well as venture private equity in generic pharmaceuticals, medical devices and oil and gas. He previously formed and managed his own investment management company early in his career and was formerly employed by E. F. Hutton and Dean Witter Reynolds. He holds a Bachelor of Arts Degree in Management and Finance from the Oakland University (1982) and was awarded a Certified Investment Management Analyst certificate in 1983 after completion of the IMCA program at the Wharton School of Business of the University of Pennsylvania. From 1996 through 2003, Mr. Joliat served on the Board of Directors of Caraco Pharmaceutical Laboratories Ltd., a company with a class of equity securities registered under the Securities Exchange Act of 1934, and served in various capacities on the audit, executive and compensation committees.
Scott R. Stevens has been a Director of the Company since the Merger on April 17, 2007. He has served on the Board of Managers of Southern Bay Energy, LLC since March 2005. He is a Vice President of Wachovia Capital Partners, which he originally joined in 1999. Wachovia Capital Partners was the principal investing arm of the Wachovia Corporation and is now a division of Wells Fargo Bank. He is a graduate of the University of North Carolina at Chapel Hill and has an MBA from the Graduate School of Business at Stanford University.
Michael A. Vlasic has been a Director of the Company since the Merger on April 17, 2007. He has served on the Board of Managers of Southern Bay Energy, LLC since its inception in 2004. He previously was a director of Texoil, Inc., a company with a class of equity securities registered under the Securities Exchange Act of 1934, where he served on the executive committee from 1997 until its sale to Ocean Energy Inc. in 2001. For more than the past five years he has been Chief Executive Manager of Vlasic Investments LLC. He is a graduate of Brown University.
Nicholas L. Voller has been a Director of the Company since March 2004. For over the past five years, he has been a partner with Voller Brakey Stillwell and Suess, P.C., a CPA firm located in Williston, North Dakota. He holds and Accounting Degree from the University of North Dakota (1972).
There is no family relationship between or among our executive officers and directors. Our directors are elected at every annual meeting of our shareholders and hold office for a one-year term or until their successors have been elected and qualified.
Committees of our Board of Directors
To assist in carrying out its duties, our Board of Directors has delegated certain authority to an Audit Committee, Nominating Committee, Compensation Committee, and Executive Committee whose functions are described below:
Audit Committee
Members: Directors Joliat (Chairman), Hunt and Voller
Number of Meetings in 2008: Four
Functions:
•
Assists the Board in fulfilling its oversight responsibilities as they relate to the Company’s accounting policies, internal controls, financial reporting practices and legal and regulatory compliance;
•
Hires the independent auditors;
•
Monitors the independence and performance of the Company’s independent auditors and internal auditors;
•
Maintains, through regularly scheduled meetings, a line of communication between the Board and the Company’s financial management, internal auditors and independent auditors; and
•
Oversees compliance with the Company’s policies for conducting business, including ethical business standards.
Index to Financial Statements The Board of Directors adopted an Audit Committee Charter in 2000 and subsequently amended and restated the Charter in March, 2004, which is available on our website at www.georesourcesinc.com.
Our Board of Directors has determined that Mr. Voller qualifies as an “audit committee financial expert” as that term is defined in the NASDAQ and SEC rules.
Our common stock is quoted on the Nasdaq Stock Market. Pursuant to Nasdaq rules, the Audit Committee is to be comprised of three or more directors as determined by the Board of Directors, each of whom shall be “independent”. Our Board of Directors has determined that all members of the Audit Committee are independent, as defined in the listing standards of the Nasdaq Stock Market and the rules of the SEC.
Nominating Committee
Members: Directors Stevens (Chairman), Hunt and Joliat
Number of Meetings in 2008: One.
On April 17, 2007, the Board of Directors adopted a resolution appointing a Nominating Committee comprised solely of directors who meet the independence requirements set forth in NASDAQ Rule 4200 and within the meaning of the rules and regulations of the SEC. On July 9, 2007, the Board of Directors approved a charter for the Nominating Committee which is available on our website, www.georesourcesinc.com. All of the research regarding director nominees for the 2007 annual meeting was performed by the entire Board of Directors sitting as a nominating committee prior to the April 17, 2007. After formation of the Nominating Committee in 2007 and the information was then referred to the Nominating Committee. The Committee followed the Board’s previous policy of nominating board candidates based on whom they believe will be effective in serving the long-term interests of the Company and its shareholders. Candidates were evaluated based upon their backgrounds and the need for any required expertise on the Board and its committees.
Our Nominating Committee will consider a candidate for a director position proposed by a shareholder. A candidate must be highly qualified in terms of business experience and be both willing and expressly interested in serving on the Board. A shareholder wishing to propose a candidate for the Board’s consideration should forward the candidate’s name and information about the candidate’s qualifications to the GeoResources, Inc., Board of Directors, Nominating Committee, Attn: Chairman, 110 Cypress Station Drive, Suite 220, Houston, Texas 77090-1629. Submissions must include sufficient biographical information concerning the recommended individual, including age, employment history for at least the past five years indicating employer’s names and description of the employer’s business, educational background and any other biographical information that would assist the Nominating Committee in determining the qualifications of the individual. The Nominating Committee will consider all candidates, whether recommended by shareholders or members of management. The Nominating Committee will consider recommendations received by a date not later than 120 calendar days before the date our proxy statement was released to shareholders in connection with the prior year’s annual meeting for nomination at that annual meeting. The Board will consider nominations received beyond that date at the annual meeting subsequent to the next annual meeting.
Compensation Committee
Members: Directors Joliat (Chairman), Hunt and Stevens
Number of Meeting in 2008: Two
On April 17, 2007, the Board of Directors adopted a resolution appointing a Compensation Committee comprised solely of directors who meet the independence requirements set forth in NASDAQ Rule 4200 and within the meaning of the rules and regulations of the SEC. On July 9, 2007, the Board of Directors approved a charter for the Compensation Committee which is available on our website, www.georesourcesinc.com. The primary function of this Committee is to review and approve executive compensation and benefit programs. Additionally, this Committee approves the compensation of the Chief Executive Officer, Chief Financial Officer, and any other officers deemed appropriate. The Compensation Committee does not anticipate utilizing any compensation consultants at this time. Our Chief Executive Officer is expected to recommend to the Compensation Committee the compensation for other executive officers and recommend director compensation.
Index to Financial Statements Executive Committee
Under the current Bylaws, Article III, Section 12, the Chairman of the Board can appoint other committees in addition to the three current standing committees: Audit, Compensation, and Nomination. On April 17, 2007, the Chairman appointed an Executive Committee to be a working committee, assigned with regular tasks outlined by our Board of Directors. The Chairman of this committee is Frank A. Lodzinski, with members Collis P. Chandler and Michael A. Vlasic. The Board of Directors has not adopted a charter for the Executive Committee.
Code of Ethics
Our Board of Directors has adopted a Code of Business Ethics (“Code”), which is posted on our website, www.georesourcesinc.com. Our shareholders may also obtain a copy of our Code by requesting it in writing at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090-1629 or by calling (281) 537-9920.
Our Code provides general statements of our expectations regarding ethical standards that we expect our directors, officers and employees to adhere to while acting on our behalf. Among other things, the Code provides that:
•
We will comply with all laws, rules and regulations;
•
Our directors, officers, and employees are to avoid conflicts of interest and are prohibited from competing with us or personally exploiting our corporate opportunities;
•
Our directors, officers, and employees are to protect our assets and maintain our confidentiality;
•
We are committed to promoting values of integrity and fair dealing; and
•
We are committed to accurately maintaining our accounting records under generally accepted accounting principles and timely filing our periodic reports.
Our code also contains procedures for employees to report, anonymously or otherwise, violations of the Code.
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company under Rule 16a-3(d) during 2008, we are not aware of any director, officer, or beneficial owner of more than 10% of our common stock that failed to file on a timely basis reports required by Section 16(a) of the Exchange Act during the year except for Wachovia Capital Partners 2005, LLC, who did not file five of its Form 4s timely. All of these filings disclosed a series of related transactions by Wachovia Capital Partners 2005, LLC over the course of seven days in June, 2008.
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Overview
The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table below. As more fully described below, the Compensation Committee of the Board of Directors reviews and recommends to the full Board of Directors the total direct compensation programs for our named executive officers. Our Chief Executive Officer, Frank A. Lodzinski, reviews the base salary, discretionary annual bonus and long-term compensation levels for the other named executive officers.
Compensation Philosophy and Objectives
Our compensation philosophy is to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow and profitability, and enhance shareholder value through a compensation program that attracts and retains highly qualified executive officers. To achieve these goals, the compensation committee believes that the compensation of executive officers should reflect our growth while ensuring fairness among the executive management team by recognizing the contributions each individual executive makes to our success.
Index to Financial Statements The compensation committee believes compensation should include the following components:
•
A base salary that is commensurate with other small, independent oil and gas companies and provides a living wage for our executive officers;
•
Discretionary annual incentive compensation to reward hard work, individual responsibility and productivity, reserve growth, performance and profitability; and
•
Long-term incentive compensation in the form of stock options.
The compensation committee periodically reviews data about the compensation of executives in the oil and gas industry but does not conduct an in-depth review of comparable companies. Based on this review, we believe that the elements of our executive compensation program are comparable to those offered by our industry competitors.
Elements of Our Compensation Program
The compensation program for our executive officers is composed of three principal components: base salary, discretionary annual incentive compensation and long-term incentive compensation in the form of stock options.
Base Salary. Base salaries (paid in cash) for our executives are established based on the scope and responsibilities, taking into account what we believe to be a fair working salary for executives in these positions, as well as competitive market compensation paid by peer companies for similar positions. All of our named executive officers have worked with or for our Chief Executive Officer, Frank A. Lodzinski, for several years. From time to time, we review our executives’ base salaries in comparison to salaries for executives in similar positions with similar responsibilities at comparable companies. Base salaries are reviewed annually and adjusted from time to time to realign salaries after taking into account individual responsibilities, performance, experience and other criteria. We rely on the advice of Mr. Lodzinski in setting base salaries for our named executive officers other than him.
The compensation committee reviews, taking into account the Chief Executive Officer’s recommendations, the base salaries for the named executive officers, except for the Chief Executive Officer, in the first quarter of each year. New base salary amounts are based on an evaluation of individual performance and expected future performance. On February 3, 2009, the compensation committee approved base salaries for our named executive officers commencing at the discretion of the Chief Executive Officer, Frank A. Lodzinski, but no earlier than April 1, 2009.
Discretionary Annual Incentive Compensation. The compensation committee recommends to the Board, and the Board subsequently approves, any annual bonuses for each named executive officer. On February 3, 2009, the compensation committee approved payment of bonuses to executive officers for 2008.
Long Term Incentive Compensation. We believe the use of stock options creates an ownership culture that encourages the long-term performance of our executive officers. In March 2007, our shareholders approved the GeoResources, Inc. Amended and Restated 2004 Employees’ Stock Incentive Plan (the “2004 Plan”). In October 2007, we issued options to the named executive officers as set forth in the table below. On the grant date all of these options were not in the money and the option exercise prices are escalated. Also on February 3, 2009, the Compensation Committee approved stock option grants to the named executive officers to purchase our common stock pursuant to our 2004 Plan. Fifty percent of the stock options are exercisable at $8.50 per share and fifty percent are exercisable at $10.00 per share. The stock options vest equally between the two exercise prices in equal annual installments over a period of four years from the date of grant. The options have a term of 10 years and are subject to the terms and conditions of the 2004 Plan. These options were not “in the money” at the date of grant in order to provide incentive for the named executive officers to continue to work diligently to increase the shareholder value through their ongoing full-time efforts. All of the above options will vest upon a change in control of the Company. We have no employment agreements with our named executive officers.
Index to Financial Statements Recent Actions. The 2008 bonus payments, 2009 base salaries and the February 2009, stock option grants are set forth in the table below.
In 2007, the Merger with Southern Bay was completed and a significant amount of work was performed by all named executive officers. However, the compensation committee, upon the advice of the Chief Executive Officer, determined that no bonus would be paid to the named executive officers other than to Jeffery P. Vickers, the former Principal Executive Officer and Principal Accounting Officer, who was instrumental in completing the Merger. For 2008, all of the named executive officers contributed significantly to the Company’s success and the Company completed acquisitions, divested non-core properties, and achieved several other strategic objectives for the year. Accordingly, the 2008 bonus payments will be made if the Company’s cash flow is sufficient as determined in the sole discretion of the Chief Executive Officer.
Other Benefits. All employees may participate in our 401(k) Retirement Savings Plan, or 401(k) Plan, established many years ago. Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. Our matching contribution is an amount equal to 100% of the employee’s elective deferral contribution not to exceed 4% of the employee’s compensation.
All full time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.
Accounting and Tax Considerations
Our option award policies have been impacted by the implementation of Statement of Financial Accounting Standards No. 123(R), which we adopted on January 1, 2006.
We have structured our compensation program to comply with Internal Revenue Code Sections 162(m) and 409A. Under Section 162(m) of the Internal Revenue Code, a limitation is placed on the tax deduction of any publically-held corporation for individual compensation to certain executives of such corporation exceeding $1,000,000 in any taxable year, unless the compensation is performance-based. If an executive officer is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with
Index to Financial Statements
Section 409A, then the benefits are taxable in the first year they are not subject to substantial risk of forfeiture. In such case, the executive officer is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit included in income. We have no individuals with non-performance based compensation paid in excess of the Internal Revenue Code Section 162(m) tax deduction limit.
Index to Financial Statements Summary Compensation Table
The following table presents the aggregate compensation earned by our named executive officers for the three fiscal years ended December 31, 2008. We do not have any employment contracts with any of our named executive officers. There has been no compensation awarded to, earned by or paid to any employees required to be reported in any table or column in the fiscal years covered by any table, other than what is set forth in the following table.
(1) These individuals were not named executive officers prior to the April 17, 2007, Merger.
The amounts disclosed for option awards are the dollar amounts recognized in the financial statements in accordance with FAS 123R. The material terms of option grants are set forth below the table “Outstanding Equity Awards at Fiscal Year-End.”
Index to Financial Statements OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
** Valued at market close price on December 31, 2008 of $8.69 per share
Option Grants in Last Two Fiscal Years. During 2008 we granted 25,000 options to non-officer employees under the Amended and Restated 2004 Employees’ Stock incentive Plan (the “2004 Plan”). We granted an aggregate of 765,000 stock options in October 2007 of which 495,000 were to the above named executive officers. If within the duration of any of the remaining outstanding options there is a corporate merger consolidation, acquisition of assets or other reorganization and if such transaction affects the optioned stock, the optionee will thereafter be entitled to receive, upon exercise of his option, those shares or securities that he would have received had the option been exercised prior to the transaction and the optionee had been a shareholder with respect to such shares. One-half of the options are exercisable on October 10, 2009, and an additional 25% are exercisable on each yearly anniversary thereafter, until October 10, 2011, when 100% of the options are exercisable.
The Compensation Committee for our Board of Directors administers the outstanding options.
Options Granted Subsequent to Year-end. On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options to officers and board members under the 2004 Plan to purchase an additional 500,000 shares of our common stock. These options vest at the rate of 25% per year beginning February 3, 2010, at exercise prices of $8.50 for 250,000 shares $10.00 for the remaining 250,000 shares. These options, if not exercised, will expire February 3, 2020. The closing price of our stock on the date of the grant was $7.62.
In 2007, our shareholders adopted the 2004 Plan. The 2004 Plan reserves 2,000,000 shares of our common stock for either nonstatutory options or incentive stock options that may be granted pursuant to the terms of the Plan. Of the 2,000,000 reserved shares, 690,000 shares remained outstanding as
Index to Financial Statements
of March 25, 2009. Under the terms of the 2004 Plan, the option price can not be less than 100% of the fair market value of the common stock of the Company on the date of grant, and if the optionee owns more than 10% of the voting stock, the option price per share can not be less than 110% of the fair market value.
Director Compensation
The following table sets forth all compensation paid to our directors in 2008.
Non-Employee Director Compensation
On February 3, 2009, the Compensation Committee of the Board of Directors of the Company adopted a compensation structure for non-employee directors effective for fiscal 2009. Each non-employee director will receive annual compensation of $23,000; each member of the Audit Committee will receive an additional $8,000 per year; and each member of the Compensation Committee will receive an additional $4,000 per year. Additionally, each non-employee director was granted stock options under the 2004 Plan to purchase 40,000 shares of common stock with exercise prices of $8.50 for 20,000 shares and $10.00 per share for the remaining 20,000 shares. The stock options vest equally between the two exercise prices in equal annual installments over a period of four years from the date of grant. The options have a term of 10 years and are subject to the terms and conditions of the 2004 Plan. The February 3, 2009, closing price of our common stock was $7.62 per share.
Employment Contracts and Termination of Employment Agreements
We have no employment contracts in place with any of our executive officers who serve at the will of the Board of Directors. We also have no compensatory plan or arrangement with respect to any executive officer where such plan or arrangement will result in payments to such officer upon or following his resignation, retirement, or other termination of employment with us and our subsidiaries, or as a result of a change-in-control of the Company or a change in the executive officers’ responsibilities following a change-in-control.
Index to Financial Statements
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 our common stock beneficially owned by each of our officers and directors and by all directors and officers as group and certain beneficial owners as of March 20, 2009. Unless otherwise indicated, the stockholders listed in this table have sole voting and investment powers with respect to the shares indicated.
Index to Financial Statements
* Less than 1%
(1) Unless otherwise indicated, the shares are held directly in the names of the named beneficial owners and each person has sole voting and sole investment power with respect to the shares.
(2) Includes 108,357 shares of common stock owned by Mr. Lodzinski, 26,400 shares held by Mr. Lodzinski’s spouse.
(3) Includes 3,833 shares of common stock held by officers and employees pursuant to a shareholders agreement
(4) Vlasic FAL, L.P., a Texas limited partnership, is managed by VL Energy LLC, a Texas limited liability company and general partner. All of the membership interest in VL Energy LLC are owned by Frank A. Lodzinski. Mr. Lodzinski and Mr. Vlasic indirectly own all of the limited partnership interests of Vlasic FAL L.P., through limited liability companies that they control, and that each of Mr. Lodzinski and Mr. Vlasic own in part, with the remaining owners consisting primarily of family members. The entity controlled by Mr. Vlasic that is the limited partner of Vlasic FAL, L.P. has the right to remove the general partner at any time. Vlasic FAL, L.P. directly owns 3,318,536 shares of the Company, or 20.4% of the issued and outstanding common stock of the Company. Based on the legal structure of Vlasic FAL, L.P., Mr. Lodzinski and Mr. Vlasic are beneficial owners of all of the shares of common stock held by Vlasic FAL, L.P., and share the right to vote and dispose of these shares. In addition, the total shares shown for Mr. Vlasic include 1,488,000 shares held by VILLCo Energy, LLC for which Mr. Vlasic serves as Chief Executive Manager.
(5) Includes 1,595,711 shares of common stock held in the name of Chandler Energy, LLC, which is solely owned by Mr. Chandler. Includes 25,000 shares that are held by Chandler Energy, LLC pursuant to a shareholders agreement with certain former employees of Chandler Energy, LLC.
(6) Includes 583 shares of common stock that have not yet vested pursuant to a shareholders agreement between Mr. Mury, Southern Bay Oil & Gas, L.P. and VL Energy, L.L.C.
(7) Includes 4,261 shares of common stock held by Mr. Ehler in an Individual Retirement Account and includes 667 shares of common stock that have not yet vested pursuant to a shareholders agreement between Mr. Ehler, Southern Bay Oil & Gas, L.P. and VL Energy, L.L.C.
(8) Includes 21,304 shares of common stock held by Mr. Anderson in an Individual Retirement Account and includes 667 shares of common stock that have not yet vested pursuant to a shareholders agreement between Mr. Anderson, Southern Bay Oil & Gas, L.P. and VL Energy, L.L.C.
(9) Includes 290,887 shares of common stock owned directly by Mr. Joliat and 184,050 shares of common stock which is owned through trusts of which Mr. Joliat is trustee. Includes 25,063 shares of common stock owned by Mr. Joliat’s wife.
(10) Mr. Stevens is a member of the managing member of Wachovia Capital Partners 2005, LLC, which owns 1,688,860 shares of the Company’s common stock. Mr. Stevens disclaims beneficial ownership of all such securities, except to the extent of his pecuniary interest therein. These securities may be deemed to be beneficially owned by (a) Wachovia Capital Partners GP I, LLC, the managing member of Wachovia Capital Partners 2005, LLC, and (b) Scott B. Pepper, Fredrick W. Eubank, II and L. Watts Hamrick, III, the managers of Wachovia Capital Partners GP I, LLC. Each of Messrs. Pepper, Eubank and Hamrick disclaims beneficial ownership of such securities except to the extent of his pecuniary interest therein.
(11) This number includes only the 3,318,536 shares of common stock in the name of Vlasic FAL, L.P. once, in which Mr. Vlasic and Mr. Lodzinski may be each considered beneficial owners of those shares. Additionally, this number only counts the shares of common stock once that have not vested for Mr. Anderson, Mr. Ehler and Mr. Mury, who share control of these shares with Mr. Lodzinski until they have vested.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
In July 2007, the Company acquired certain oil and gas properties from officers and key employees for $1,075,000, including cash of $856,000 and the issuance of 30,406 shares of common stock at $7.19 per share. Also, in July 2007, the Company issued 100,000 shares of common stock for cash of $719,000 to three individuals, including two members of the board of directors and an affiliate of one of our directors.
Index to Financial Statements Accounts receivable at December 31, 2008 and 2007, includes $2,311,000 and $3,360,000 respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at December 31, 2008, also includes $594,000 due from OKLA Energy Partners LP. Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at December 31, 2008 and 2007, includes $9,333,000 and $9,538,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at December 31, 2008, also includes $977,000 due to OKLA Energy for oil and gas revenues collected on its behalf.
The Company earned partnership management fees during the years ended December 31, 2008, 2007, and 2006 of $1,725,000, $969,000, and $260,000 respectively.
Subsidiaries of the Company operate the majority of oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on each partnership’s behalf. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.
Independence of Directors
The rules of the Nasdaq Stock Market require that a majority of our Board of Directors be independent directors, as defined in Nasdaq Rule 4200(a)(15). In March 2006, April 2007, and October 2008, we reviewed the independence of our directors. During these reviews, our Board of Directors considered transactions and relationships between each director, or any member of his family, and the Company and our subsidiaries. As a result of this review, the Board of Directors has determined that a majority of the directors serving on the Board are independent under Nasdaq Rules. Our independent directors are: Messrs. Hunt, Joliat, Stevens and Voller.
Index to Financial Statements
Item 14.
Item 14. Principal Accountant Fees and Services
During 2008, 2007 and 2006, we paid the following fees to our principal accountants:
To help assure independence of the independent auditors, the Audit Committee of our Board of Directors has established a policy whereby all audit, review, attest and non-audit engagements of the principal auditor or other firms must be approved in advance by the Audit Committee; provided, however, that de minimis non-audit services may instead be approved in accordance with applicable Securities and Exchange Commission rules. This policy is set forth in our Audit Committee Charter. Of the fees shown above in the table, which were paid to our principal accountants, 100% were approved by the Audit Committee.
Index to Financial Statements
Item 15.
Item 15. Exhibits and Financial Statement Schedules
EXHIBIT INDEX
FOR
Form 10-K for the year ended December 31, 2008.
Index to Financial Statements
(1) Filed herewith.
(2) Filed with the Registrant’s Form 10-QSB for the quarter ended September 30, 2007.
(3) Filed with the Registrant’s Form 10-QSB for the quarter ended June 30, 2007.
(4) Filed with the Registrant’s Form 8-K on June 11, 2008.
(5) Filed with the Registrant’s Form 10-KSB for the year ended December 31, 2007.
(6) Filed with the Registrant’s Form 10-Q for the quarter ended June 30, 2008.
(7) Filed with the Registrant’s Form 10-Q for the quarter ended September 30, 2008.
Index to Financial Statements GEORESOURCES, INC. and SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS
Index to Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of GeoResources, Inc.:
We have audited the accompanying consolidated balance sheets of GeoResources, Inc. (a Colorado corporation) and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements in income, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes, examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoResources, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Houston, Texas
March 25,
Index to Financial Statements GEORESOURCES, INC and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these statements.
Index to Financial Statements GEORESOURCES, INC and SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these statements.
Index to Financial Statements GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these statements
Index to Financial Statements GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY and COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2008, 2007 and 2006
(In thousands except share data)
The accompanying notes are an integral part of these statements.
Index to Financial Statements GEORESOURCES, INC. and SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these statements.
Index to Financial Statements GEORESOURCES, INC. and SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008, 2007 and 2006
NOTE A: Organization and Summary of Significant Accounting Policies
Merger
On April 17, 2007, pursuant to the terms of an Agreement and Plan of Merger (“Merger Agreement”), GeoResources, Inc. (“GeoResources” or the “Company”), a Colorado corporation, acquired Southern Bay Oil & Gas, L.P. (“Southern Bay”), a Texas limited partnership, PICA Energy, LLC (“PICA”), a Colorado limited liability company and subsidiary of Chandler Energy LLC, and certain oil and gas properties in exchange for 10,690,000 shares of common stock (the “Merger”). These transactions resulted in a change in stockholder control of the Company. As a result of the Merger, the former Southern Bay partners received a majority of the outstanding common stock of the Company and thus, obtained voting control of the Company. Accordingly, for financial reporting purposes, the Merger was accounted for as a reverse acquisition of GeoResources and PICA by Southern Bay. Therefore, the results of operations and cash flows as presented herein for the year ended December 31, 2008 are those attributable to the combined entities. The results of operations and cash flows for the year ended December 31, 2007 are those attributable to the former Southern Bay entity for the entire twelve months and those of the combined entity for the period from April 18, 2007, through December 31, 2007. The results of operations and cash flows for the year ended December 31, 2006, are those attributable to the former Southern Bay entity.
Organization and Basis of Presentation
GeoResources operates a single business segment involved in the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, Louisiana, Oklahoma, North Dakota, Montana and Colorado.
Summary of Significant Accounting Policies
Basis of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Intercompany accounts and transactions have been eliminated. The Company’s investments in oil and gas limited partnerships for which it serves as general partner are accounted for under the equity method.
All events described or referred to as prior to April 18, 2007, relate to Southern Bay as the accounting acquirer.
Prior Year Reclassification
Certain reclassifications have been made to prior period amounts to conform to current period presentation of revenues and royalties payable in the Consolidated Balance Sheet as of December 31, 2007.
Cash and Cash Equivalents
Cash and cash equivalents consists of all demand deposits and funds invested in highly liquid investments with an original maturity of three months or less.
The Company maintains its cash and cash equivalents at financial institutions. The combined account balances at several institutions typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. Management believes that this risk is not significant.
Index to Financial Statements Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for oil and gas operations whereby cost to acquire mineral investments in oil and gas properties, to drill successful exploratory wells, to drill and equip development wells, and to install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. The Company’s acquisition and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers.
Oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to its estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on expected future cash flows using discount rates commensurate with the risks involved and using prices and costs consistent with those used for internal decision making. Long-lived assets committed by the Company for disposal are accounted for at the lower of cost or fair value, less cost to sell. The Company recognized impairments of $9,194,000 for the year ended December 31, 2008. Impairments of $8,339,000 were recognized on proved properties and are classified as impairments on the Company’s income statement. The remaining $855,000 of impairments resulted from the write-off of unproved properties during the second and fourth quarters of 2008 and is included in exploration expense on the Company’s Consolidated Statement of Income. The Company recognized no impairments and $184,000 for the years ended December 31, 2007 and 2006, respectively.
Office and Other Property
Acquisitions and improvements of office and other property are capitalized at cost; maintenance and repairs are expensed as incurred. Depreciation of equipment is calculated using the straight-line method over the assets estimated useful lives of 5-7 years. Leasehold improvements are amortized over the remaining term of the lease. When assets are sold, retired, or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized.
Net Income Per Common Share
Basic net income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations to reconcile basic and diluted net income for 2008, 2007 and 2006 consist of the following (in thousands except per share data):
Options to purchase 25,000 shares were excluded from the diluted earnings per share calculation in 2008 because the options’ exercise prices exceeded the average market price of the common shares during the period.
Index to Financial Statements On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options to officers and board members to purchase an additional 500,000 share of the Company’s common stock, for further information see Note D below.
Stock-Based Compensation
Effective January 1, 2006, the Company accounts for stock-based compensation in accordance with SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable and payable and revenue royalties payable are estimated to approximate their fair values due to the short maturities of these instruments. The Company’s long-term debt obligation bears interest at floating market rates, so carrying amounts and fair values are approximately the equal. Derivative financial instruments are carried at fair value.
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes are based on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement, with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance is provided for deferred tax assets not expected to be realized.
Other Comprehensive Income (Loss)
The Company follows SFAS No. 130, “Reporting Comprehensive Income”, which established standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. Other comprehensive income (loss) at December 31, 2008, 2007 and 2006 consists of unrealized gains (losses) of commodity hedges qualifying as cash flow hedges in accordance with SFAS No. 133.
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 reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Oil and gas reserve estimates, which are the basis for units-of-production depletion, are inherently imprecise and are expected to change as future information becomes available.
Derivative Instruments and Hedging Activities
The Company enters into derivative contracts, primarily options, collars and swaps, to hedge future crude oil and natural gas production, as well as interest rates, in order to mitigate the risk of downward movements of oil and gas market prices and the upward movement of interest rates. As required, the Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Under SFAS No. 133, all derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify either as a fair value, cash flow or foreign currency hedge.
Index to Financial Statements The hedging relationship between the hedged instruments and hedged transactions must be highly effective in achieving the offset of changes in fair values and cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes in intrinsic value only. As a result, changes in the entire value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affects earnings to the extent such contracts are effective. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.
Gains and losses resulting from hedge settlements are included in oil and gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments that represent hedge ineffectiveness and gains and losses on derivative instruments that do not qualify for hedge accounting are included in other revenues or expenses in the period in which they occur. The resulting cash flows are reported as cash flows from operating activities.
Asset Retirement Obligations
In accordance with the requirements of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“ARO”), the Company recognizes the present value of the estimated future abandonment costs of its oil and gas properties in both assets and liabilities. If a reasonable estimate of the fair value can be made, the Company will record a liability for legal obligations associated with the future retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal operation of the assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is incurred. The fair value is measured using expected future cash outflows (estimated using current prices that are escalated by an assumed inflation rate) discounted at the Company’s credit-adjusted risk-free interest rate. The liability is then accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the asset retirement obligation is capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset.
The Company has recorded asset retirement obligations related to its oil and gas properties. There are no assets legally restricted for the purpose of settling asset retirement obligations.
Revenue Recognition
Revenues represent income from production and delivery of oil and gas, recorded net of royalties. The Company follows the sales method of accounting for gas imbalances. A liability is recorded only if the Company’s takes of gas volumes exceed its share of estimated recoverable reserves from the respective well or field. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 2008, 2007 or 2006.
Accounts Receivable
The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which subsidiaries of the Company serve as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.
As is common industry practice, the Company generally does not require collateral or other security as a condition of sale, rather relying on credit approval, balance limitation and monitoring procedures to control the credit use on accounts receivable. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any
Index to Financial Statements
collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance.
Accounts receivable allowance for bad debt was $150,000 at December 31, 2008 and 2007.
Recently Issued Accounting Pronouncements
On December 31, 2008, the SEC published the revised rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in existing oil and gas rules to make them consistent with the petroleum resources management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used in determining reserves. To determine reserves companies must use a 12-month average price. The Company is required to comply with the amended disclosure requirement for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. We are currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.
In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 161, Disclosure about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133 (“SFAS 161”). The adoption of SFAS 161 is not expected to have an impact on the Company’s consolidated financial statements, other than additional disclosures. SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.
In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51 (“SFAS 160”). This statement amends ARB No. 51 and intends to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards on the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. SFAS 160 is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The Company does not believe that this statement will have a material impact on its consolidated financial statements.
In December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R may have an impact on the Company’s consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms, and size of the acquisitions that the Company consummates after the effective date. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company intends to adopt SFAS 141R effective January 1, 2009, and apply its provisions prospectively.
In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). This new standard permits an entity to make an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS 159 was effective as of the beginning of the first fiscal year beginning after November 15, 2007. The Company elected not to adopt the fair value option provision allowed under SFAS 159.
Index to Financial Statements NOTE B: Significant Acquisitions
Merger
The net assets of the acquired GeoResources and PICA as well as certain other acquired oil and gas properties pursuant to the Merger, which occurred on April 17, 2007, were recorded at fair value using the purchase method of accounting, as required by generally accepted accounting principles. Such net assets consisted of cash and other current assets and liabilities, oil and gas properties, certain mineral leases and options, and debt. The fair value of the net assets acquired in these purchases was based on the average trading price of GeoResources common stock immediately before and after the public announcement of the Merger Agreement, of $6.29 per share.
The following is a summary of the assets acquired and liabilities assumed in the Merger (in thousands):
AROC Energy Acquisition
October 16, 2007, the Company, through a wholly-owned subsidiary, entered into an agreement to purchase (“Purchase Agreement”) all of the limited partnership interest in AROC Energy, L.P., an affiliated limited partnership for which the Company served as general partner. The limited partner was an unaffiliated entity. Prior to this transaction, the Company owned 2% of the partnership and the limited partner owned the remaining 98%. This acquisition, which was accounted for as a purchase, included oil and gas properties located in Louisiana, the Gulf Coast, South Texas, the Permian Basin and the Black Warrior Basin.
Under the Purchase Agreement, the Company purchased the interest for a cash purchase price of $91,100,000 and paid $12,952,000 to cancel the limited partnership’s oil and gas hedge contracts. These costs were funded with cash of $8,052,000 and borrowings of $96 million under the Amended Credit Agreement discussed in Note C. The Company also paid its bank a fee of $1,250,000 in connection with the acquisition. The purchase of the interest was effective on the date of closing of the Purchase Agreement, October 16, 2007, and resulted in the Company’s total ownership percentage of 100% of the limited partnership. In November 2007, the Company dissolved the limited partnership.
Index to Financial Statements The following is a summary of the underlying assets and liabilities attributable to the acquired interest (in thousands):
Other Acquisitions and Dispositions
In January 2007, Southern Bay formed two entities in connection with the acquisition of producing oil and gas properties located in southeast Texas. Catena Oil & Gas LLC (“Catena”) was formed as an indirect wholly-owned subsidiary of Southern Bay and SBE Partners LP (“SBE”) was formed with Catena as general partner with a 2% partnership interest, and a large institutional investor as the sole limited partner with a 98% partnership interest. In February, 2007 these entities paid cash of $82 million to acquire certain southeast Texas properties. Catena purchased 8% of the interests and SBE purchased the remaining 92%. Catena’s share of the property purchase price was $6.6 million, and its general partner contribution to SBE was $1.6 million. Southern Bay funded these amounts with additional capital contributions from its partners of $5.0 million, borrowings under its bank credit agreement of $3.0 million and working capital of $200,000. The Company’s investment in SBE is accounted for under the equity method of accounting.
In May 2008, Southern Bay, through Catena, formed an entity in connection with the acquisition of producing oil and gas properties located throughout Oklahoma. OKLA Energy Partners LP (“OKLA”) was formed with Catena as general partner with a 2% partnership interest, and a large institutional investor as the sole limited partner with a 98% partnership interest. In May, 2008, these entities paid cash of $61.7 million to acquire certain Oklahoma properties. Catena, purchased 18% of the interests and OKLA purchased the remaining 82%. Catena’s share of the property purchase price was $12.8 million, and its general partner contribution to OKLA was $978,000. The Company’s investment in OKLA is accounted for under the equity method of accounting.
In January 2008, the Company sold all of its interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was sold to an unaffiliated party for $6.6 million in cash. The carrying value of this property at the date of the sale was equal to the selling price; therefore, no gain or loss was recognized on sale.
In February 2008, the Company acquired producing properties in the Williston Basin of North Dakota and Montana from an unaffiliated party for $7.9 million in cash. The acquired properties are operated by the Company. The purchase price was allocated to oil and gas properties.
In February 2008, the Company sold its interests in certain non-core oil and gas properties located in Louisiana to unaffiliated parties for $1.8 million in cash and recognized gains of $430,000.
In May 2008, the Company closed certain property sales. These sales consisted of seven non-core fields in Louisiana and Texas and were sold to unaffiliated parties for approximately $11.8 million. The Company recognized a gain of $1.5 million related to these sales.
Index to Financial Statements In September 2008, the Company acquired certain producing properties in Oklahoma from an unaffiliated party for $3.6 million in cash. The acquired properties are operated by the Company. The purchase price was allocated to oil and gas properties.
During 2008, the Company identified an exploration opportunity and began leasing in various counties in Colorado and Utah targeting the Gothic Shale as a newly emerging resource play with multiple other objectives. In November, 2008, the Company sold the majority of its interest for $6 million and recognized a gain of $2.5 million. The Company retained an overriding royalty interest or the option to participate, under certain circumstances, for up to 12.5% working interest.
NOTE C: Long-term debt
On September 26, 2007, the Company entered into a Credit Agreement with Wachovia Bank, as Administrative Agent and Issuing Bank and U.S. Bank as Lenders. This agreement provided for a Senior Secured Revolving Credit Facility in the maximum amount of $100 million, with an initial borrowing base of $35 million.
On October 16, 2007, the Company entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”) with Wachovia Bank (the “Bank”) as Administrative agent, Issuing Bank, Sole Lead Arranger and Sole Bookrunner. The Amended Credit Agreement provides for financing of up to $200 million to the Company. The initial borrowing base of the Amended Credit Facility was $110 million, subject to redetermination on April 1 and October 1 of each year. On September 30, 2008, the borrowing was reduced to $95 million due to the sales of certain non-core oil and gas properties. On November 5, 2008, the borrowing base was increased to $100 million and the Amended Credit Agreement was amended to provide for interest rates at (a) LIBOR plus 1.75% to 2.50%, or (b) the prime lending rate plus .75% to 1.50%, depending on the amount borrowed. Principal amounts outstanding under this Amended Credit Agreement are due and payable in full at maturity on October 16, 2010. The Amended Credit Agreement also requires the payment of commitment fees to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.375% to 0.50% per year depending on the amount of borrowing base utilization. The Company is also required to pay customary letter of credit fees. All of the obligations under the Amended Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.
On October 16, 2007, the Company borrowed $96.0 million under the Amended Credit Agreement, in connection with the AROC Energy acquisition. The Company also paid the Bank transaction fees of $1.25 million as well as underwriting fees and other loan costs totaling $1.25 million. At December 31, 2008, the outstanding principal balance was $40.0 million. The annual interest rate in effect at December 31, 2008 was 2.97% on the entire amount of the outstanding principal.
Also, in October 2007, the Company entered into an interest rate swap agreement with the Bank, providing a fixed rate of 4.29% on a notional $50,000,000 through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap. The $40 million swap is accounted for as a cash flow hedge while the $10 million swap is accounted for as a trading security. The fair market value of these swaps at December 31, 2008, was a liability of $2,817,000 of which $1,572,000 is classified as a current liability. The Company also recognized a loss of $563,000 on the $10 million swap during 2008 and no gain or loss was recognized on the swap existing during 2007. The value of the swap at December, 31, 2007 was a liability of $854,000, of which $476,000 was classified as a current liability.
At December 31, 2008, accumulated other comprehensive income included unrecognized losses of $1,394,000, net of a tax benefit of $859,000, representing the inception to date change in mark-to-market value of the Company’s $40 million interest rate swap, designated as a hedge, as of the balance sheet date. At December 31, 2007, accumulated other comprehensive income (loss) included $854,000 of unrecognized losses, representing the inception to date change in mark-to-market value of the Company’s $50 million interest rate swap. For the year ended December 31, 2008, the Company recognized realized cash settlement losses of $656,000 related to its two swaps. The Company did not have any settlement losses related to its interest rate swap in 2007. Based on the estimated fair market value of the Company’s $40 million derivative contract designated as a hedge at December 31, 2008, the Company expects to reclassify net losses of $1.3 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
Index to Financial Statements The Amended Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and lease back transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Amended Credit Agreement requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at December 31, 2008.
The principal outstanding under the Amended Credit Agreement was $40.0 million at December 31, 2008. The principal outstanding at December 31, 2007, was $96.0 million, which borrowing was made in connection with the AROC Energy acquisition in October 2007. The remaining borrowing capacity under the Amended Credit Agreement at December 31, 2008, was $60.0 million. The maturity date for amounts outstanding under this agreement is October 16, 2010.
The weighted average interest rate on borrowings outstanding during 2008, 2007, and 2006 was 6.42%, 7.63% and 8.21%, respectively.
Interest expense for 2008, 2007 and 2006 includes amortization of deferred financing costs of $491,000, $146,000 and $47,000, respectively.
NOTE D: Stock Options, Performance Awards and Stock Warrants
In March 2007, the shareholders the Company approved the GeoResources, Inc, Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options.
On October 10, 2007, and November 10, 2007, the Company granted options under the Plan to officers and key employees to purchase 755,000 and 10,000 shares of common stock, respectively. On June 19, 2008, the Company granted options to employees to purchase 25,000 shares of common stock. The following is a summary of the terms of these grants:
The closing market prices of the Company’s common stock on the date of the October and November 2007 grants were $7.20 and $8.65, respectively. The closing market price of the Company’s common stock on the date of the June 2008 grant was $20.99.
On February 3, 2009, the Compensation Committee of the Board of Directors granted additional options to officers and board member to purchase an additional 500,000 shares of the Company’s common stock. These options vest at the rate of 25% per year beginning February 3, 2010, at an exercise price of $8.50 for 250,000 shares and $10.00 for the remaining 250,000 shares. The closing price of the Company’s stock on February 3, 2009 was $7.62.
Index to Financial Statements The options, if not exercised, will expire 10 years from the date of grant.
A summary of the Company’s stock option activity for the year ended December 31, 2008 and 2007 is as follows:
The Company accounts for these stock option under the provision of Statement of Financial Accounting Standards No. 123R, “Share Based Payment” and accordingly, recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the years ended December 31, 2008 and 2007 the Company recognized compensation expense of $626,000 and $131,000, respectively, related to these options. As of December 31, 2008, the future pre-tax expense of non-vested stock options is $1,025,000 to be recognized through 2011.
During 2008 and 2007, the weighted-average fair value of the options granted during the year was $6.82 per share and $2.14 per share, respectively, using the following assumptions:
In measuring compensation associated with these options, an annual pre-vesting forfeiture rate of 1% was used.
Partnership Equity Incentive Plan
Prior to the Merger, Southern Bay had an equity incentive plan to provide incentives to employees and independent contractors of Southern Bay by providing such persons with partnership interests designated as Class B units and Class C units. Units issued under this plan were subject to vesting requirements and, in addition, Class C units did not participate in profits, losses or cash distributions until the Class A units had received certain minimum cash distributions. This plan was terminated in connection with the Merger on April 17, 2007.
Index to Financial Statements Southern Bay adopted the provisions of SFAS 123R, “Share-Based Paymnent” effective January 1, 2006 and as a result, recognized compensation expense of $422,000 for 2006 and $422,000 in 2007, through the date of the Merger.
NOTE E: Income Taxes
As a partnership, Southern Bay was generally not subject to federal or state income taxes on its taxable income. The taxable income and deductions were reported by the partners in their respective returns. Therefore, except for the recognition of deferred Texas Margin Tax in 2006, no income taxes were reported by Southern Bay prior to the Merger.
The following table shows the components of the Company’s income tax provision for 2008 and 2007:
The following is a reconciliation of taxes computed at the corporate federal statutory income tax rate of 35% in 2008 and 34% in 2007 to the reported income tax provision for the years ended December 31, 2008 and 2007:
Deferred income taxes are recognized for the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and tax purposes, as required by SFAS No. 109, and clarified by FIN 48. The deferred tax is measured using the enacted tax rates applicable to periods when these differences are expected to reverse.
Index to Financial Statements The deferred income tax provision for 2007 includes an initial charge of $2,214,000 attributable to Southern Bay becoming at taxable entity in April 2007, concurrent with the Merger. Generally accepted accounting principles require the recognition of deferred taxes attributable to temporary differences existing at the date of a change in status of an entity from nontaxable to taxable.
The following table shows the components of the Company’s net deferred tax liability at December 31, 2008 and 2007:
As of December 31, 2008 and 2007, the Company had statutory depletion available for carryforward of approximately $5.1 million and $7.0 million, respectively, which may be used to offset future taxable income. The amount that may be used in any year is subject to limitations arising from a change in control resulting from the Merger.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FIN 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect adjustment to retained earnings, our financial condition or results of operations as a result of implementing FIN 48. The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing FIN 48. The amount of unrecognized tax benefits did not materially change during the years ended December 31, 2008 or 2007.
It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, we do not expect the change to have a significant impact on the results of operations or the financial position of the Company.
The Company files a consolidated federal income tax return and various combined and separate filings in several state and local jurisdictions.
The Company’s continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated
Index to Financial Statements
Statements of Income. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during 2008. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2009.
NOTE F: Derivative Financial Instruments
The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements. The Company does not enter into commodity derivative instruments for speculative or trading purposes.
At December 31, 2008, accumulated other comprehensive income (loss) consisted of unrecognized gains of $8,677,000, net of taxes of $5,348,000, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2007, accumulated other comprehensive income (loss) consisted of $18,456,000 of unrecognized losses. For the years ended December 31, 2008, 2007 and 2006, the Company recognized realized cash settlement losses on commodity derivatives of $9,970,000, $2,910,000 and $1,807,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at December 31, 2008, the Company expects to reclassify net gains of $8,200,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
On October 17, 2008, the Company paid $2,975,000 to cancel its 2009 natural gas swaps that were previously accounted for as cash flow hedges. At the time of cancelation, accumulated other comprehensive (loss) contained $482,000 of acquisition to date change in mark-to-market of the effective portion of these commodity derivative contracts. These accumulated losses will be amortized during 2009 and reduce net income by $482,000. The remainder of the cost to cancel was previously recognized as part of the AROC Energy acquisition or through ineffectiveness charges. The canceled swaps were acquired as part of the AROC Energy acquisition discussed in Note B.
At December 31, 2008, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:
Index to Financial Statements The fair market value of these hedge contracts at December 31, 2008 was an asset of $14,609,000 of which $8,200,000 was classified as a current asset. The fair market value of the Company’s hedge contracts at December 31, 2007 was a liability of $20,969,000, of which $6,051,000 was classified as a current liability. During the year ended December 31, 2008, the Company recognized a gain of $123,000 due to hedge ineffectiveness on these hedge contracts versus a loss of $287,000 during 2007. During the year ended December 31, 2006, the Company recognized a gain of $393,000 due to hedge ineffectiveness.
The Company has also entered into an interest rate swap designated as a cash flow hedge as discussed in Note C above.
NOTE G: Fair Value Disclosures
SFAS 157 - Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS 157 did not cause a change in the method of calculating fair value assets or liabilities. The primary impact from adoption was additional disclosures.
The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2 Effective Date of FASB No. 157 (“FSP 157-2”), issued February 2008, which defers the effective date of SFAS 157 for one year, until fiscal years beginning after November 15, 2008, for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis As it relates to the Company, the deferral applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value, impaired oil and gas property assessments, and the initial recognition of asset retirement obligations for which fair value is used. The Company does not believe that the implementation of the deferred provisions of SFAS 157 will cause the Company to changes its method of calculation fair value of certain nonfinancial assets or liabilities. The Company expects that the primary impact from adoption of these remaining provisions will be additional disclosures.
In October 2008, the FASB issued FASB Staff Position No. FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (“FSP 157-3”), which clarifies the application of SFAS 157 in an inactive market and provides an example to demonstrate how the fair value of a financial assets is determined when the market for that financial asset is inactive. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. FSP 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued.
Fair Value Hierarchy - SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•
Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•
Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•
Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or
Index to Financial Statements
liability. The following table presents information about the Company’s liabilities measured at fair value on a recurring basis as of December 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:
(1) Commodity derivative instruments accounted for as cash flow hedges.
(2) Includes a $40 million interest rate swap accounted for as a cash flow hedge ($1,258,000) and a $10 million interest rate swap accounted for as a trading security ($314,000).
(3) Includes a $40 million interest rate swap accounted for as a cash flow hedge ($996,000) and a $10 million interest rate swap accounted for as a trading security ($249,000).
Commodity Derivative Instruments - Commodity derivative instruments consist of costless collars and swaps for crude oil and natural gas. The Company’s costless collars are valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is the NYMEX futures index. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy. The discount rate used in determining the fair values of these instruments includes a measure of nonperformance risk.
Interest Rate Swap - The Company’s interest rate swap is valued using the counterparty’s marked-to-market statement, which can be validated using modeling techniques that include market inputs such as publically available interest rate yield curves, and is designated as Level 2 within the valuation hierarchy.
At December 31, 2008, the Company has no assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.
NOTE H: Private Placement Offering
On June 5, 2008, the Company issued 1,533,334 shares of common stock and 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The shares of common stock were sold for $22.50 per share. The warrants have a term of five years with an exercise price of $32.43. The gross proceeds to the Company of $34.5 million were reduced by placement fees and issue costs of $2.3 million.
Index to Financial Statements NOTE I: Asset Retirement Obligations
The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. In accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), the Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the years ended December 31, 2008 and 2007, are as follows (in thousands):
NOTE J: Concentration of Credit Risk
Credit risk represents the accounting loss which the Company would record if its customers failed to perform pursuant to the contractual terms. The Company’s largest customers are large multinational companies. In addition, the Company transacts business with independent oil producers, crude oil trading companies and a variety of other entities. The Company’s credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables.
In 2008, one purchaser accounted for 16% of the Company’s consolidated oil and gas revenue, two more accounted for 11% each and two purchasers accounted for 10% each. In 2007, two purchasers accounted for 17% and 14% of consolidated oil and gas revenues. In 2006, four purchasers accounted for 27%, 18%, 15% and 12% of consolidated oil and gas revenues. No other single purchaser accounted for 10% or more of our consolidated oil and gas revenues in 2008, 2007, or 2006. There are adequate alternate purchasers of our production such that we believe the loss of one or more of the above purchasers would not have a material adverse effect on our results of operations or cash flows.
NOTE K: Commitments and Contingencies
Commitments
The Company is obligated under non-cancelable operating leases for its office facilities as follow (in thousands):
Total rental expense under operating leases for 2008, 2007 and 2006 was $324,000, $246,000 and $164,000, respectively.
Index to Financial Statements Contingencies
No significant legal proceedings are pending which are expected to have a material adverse effect on the Company. The Company is unaware of any potential claims or lawsuits involving environmental, operating or corporate matters which are expected to have a material adverse effect on the Company’s financial position or results of operations.
NOTE L: Related Party Transactions
In July 2007, the Company acquired oil and gas properties from certain officers and key employees for $1,075,000, including cash of $856,000 and the issuance of 30,406 shares of common stock at $7.19 per share. Also, in July 2007, the Company issued 100,000 shares of common stock for cash of $719,000 to three individuals, including two members of the board of directors and an affiliate of one of the Company’s directors.
Accounts receivable at December 31, 2008 and 2007, includes $2,311,000 and $3,360,000 respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at December 31, 2008, also includes $594,000 due from OKLA Energy Partners LP. Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at December 31, 2008 and 2007, includes $9,333,000 and $9,538,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at December 31, 2008, also includes $977,000 due to OKLA Energy for oil and gas revenues collected on its behalf.
The Company earned partnership management fees during the years ended December 31, 2008, 2007, and 2006 of $1,725,000, $969,000, and $260,000 respectively.
Subsidiaries of the Company operate the majority of oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on each partnership’s behalf. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.
Index to Financial Statements NOTE M: Supplemental Financial Quarterly Results (unaudited):
The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss) per share amounts as a result of each period’s computation being based on the weighted average number of common shares outstanding during that period.
(1) Partnership management fees, property operating income, gain (loss) on sale of property and partnership income.
(2) Lease operating expense, production taxes, re-engineering & workover, exploration, and depreciation depletion and amortization.
(3) Other Income (expense), net for the fourth quarter of 2008 included impairment expense of $8.3 million.
Index to Financial Statements NOTE N: SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
1. Costs incurred related to oil and gas activities
The following two unaudited tables set forth costs incurred during the years ended December 31, 2008, 2007 and 2006.
Costs incurred in acquisition, development and exploration:
Capitalized cost of oil and gas properties:
The amounts included in unproved properties are projects for which the Company intends to commence exploration or evaluation projects in the near future. Of the approximately $2.4 million in net unevaluated property costs at December 31, 2008, that are being excluded from the amortizable base, approximately $1.3 million was incurred in 2007 and $1.0 million was incurred in 2006. The Company will begin to amortize these costs when proved reserves are established or an impairment is determined.
2. Estimated Quantities of Proved Oil and Gas Reserves
The estimates of proved oil and gas reserves are based on a report by independent petroleum engineers. The estimates at December 31, 2008, 2007 and 2006 were prepared by Cawley, Gillespie & Associates, Inc. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of mature producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. In addition, a portion of the Company’s proved reserves is undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.
Index to Financial Statements Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the years ended December 31, 2008, 2007 and 2006:
Oil and Gas Reserve Quantities (in thousands):
3. Discounted Future Net Cash Flows
In accordance with SFAS No. 69, estimates of standardized measure of discounted future cash flows were determined by applying period-end prices (adjusted for location and quality differentials) to the estimated future production of year-end proved reserves. Future cash inflows were reduced by the estimated future production and development costs based on period-end costs to determine pre-tax cash inflows in the associated proved oil and gas properties. Estimated future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion, depletion carryforwards, net operating loss carryforwards, and investment tax credit carryforwards. Future net cash inflows were discounted using a 10% annual discount rate to arrive at the standardized measure.
The standardized measure of discounted future net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of oil and gas properties. No value has been given to unproved properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Future realization of oil and gas prices over the remaining reserve lives may vary significantly from current prices. In addition, the method of valuation utilized, based on year-end prices and costs and the use of a 10% discount rate is not necessarily appropriate for determining fair value.
Index to Financial Statements Presented below is the standardized measure of discounted future net cash flows as of December 31, 2008, 2007 and 2006.
Standardized Measure of Estimated Future Net Cash Flows
The principal sources of changes in the standardized measure of discounted future net cash flows for 2008, 2007 and 2006 are as follows:
Changes in Standardized Measure
Equity in Partnership Reserves
1. Costs incurred related to oil and gas activities
The following two unaudited tables set forth the Company’s share of costs incurred in the affiliated partnerships during the years ended December 31, 2008 and 2007. During 2006, the Company did not hold an interest in either one of the affiliated partnerships that it accounted for using the equity method at December 31, 2008.
Index to Financial Statements Costs incurred in acquisition, development and exploration:
Capitalized cost of oil and gas properties:
2. Estimated Quantities of Proved Oil and Gas Reserves and Discounted Future Net Cash Flows
The reserve information presented above does not include the Company’s share of reserves held by two limited partnerships which are accounted for under the equity method of accounting. The following table presents the Company’s estimated share of the oil and gas reserves held by the limited partnerships as of December 31, 2008.
Index to Financial Statements Signatures
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
(Power of Attorney)
Each person whose signature below constitutes and appoints FRANK A. LODZINSKI and HOWARD E. EHLER his true and lawful attorneys-in-fact and agents, each acting along, with full power of stead, in any and all capacities, to sign any or all amendments to this annual report on Form 10-K for the year ended December 31, 2008, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in each acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue thereof.