GeoResources 10-K 2011
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Annual Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the Fiscal Year ended December 31, 2010
Commission File Number 0-8041
(Exact name of registrant as specified in its charter)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Indicated by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes ¨ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicated by check mark whether the registrant is a large accelerated file, an accelerated file, a non-accelerated filer, or a smaller reporting company. (Check one):
Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2010: $180,766,713
Number of shares of the registrants common stock outstanding at March 10, 2011: 25,420,842
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this report incorporates by reference certain portions of the definitive proxy materials of the registrant in respect of its 2011 Annual Meeting of Shareholders.
TABLE OF CONTENTS
Certain statements contained in this report on Form 10-K are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the Securities Act) and the Securities Exchange Act of 1934, as amended (the Exchange Act), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as believes, anticipates, expects, intends, targeted, may, will and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:
Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.
Unless the context otherwise requires, the terms we, us, our or ours when used in this report refer to GeoResources, Inc., together with its consolidated operating subsidiaries. When the context requires, we refer to these entities separately.
We have included below the definitions for certain terms used in this report:
After payout With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.
AMI Area of Mutual Interest
Bbl One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d or BOPD barrels per day.
Bcf Billion cubic feet.
Bcfe Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Before payout With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.
Behind-pipe reserves Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells.
BOE Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
Carried interest A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.
Completion The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Compression A force that tends to shorten or squeeze, decreasing volume or increasing pressure.
DD&A Depreciation, depletion and amortization.
Developed acreage The number of acres which are allotted or assignable to producing wells or wells capable of production.
Development activities Activities following exploration including the installation of facilities and the drilling and completion of wells for production purposes.
Development well A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well A well found to be incapable of producing hydrocarbons economically.
Exploitation The act of making oil and gas property more profitable, productive or useful.
Exploratory well - A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Farm-in or Farm-out An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by the assignee is a farm-in while the interest transferred by the assignor is a farm-out.
FASB The Financial Accounting Standards Board.
Field An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP Generally accepted accounting principles in the United States of America.
Gross acres or gross wells The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques that may, depending on horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.
Injection well A well used to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.
MBbls One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE one thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
Mbtu (Mmbtu) Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often expressed as MMBTU, which is intended to represent a thousand BTUs.
Mcf One thousand cubic feet.
Mcf/d One thousand cubic feet per day.
Mcfe One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.
MMcf One million cubic feet.
MMcf/d One million cubic feet per day.
MMcfe One million cubic feet equivalent.
Net acres or net wells The sum of the fractional working interests owned in gross acres or gross wells.
NGLs Natural gas liquids measured in barrels.
NRI or Net Revenue Interests The share of production after satisfaction of all royalty, oil payments and other non-operating interests.
Normally pressured reservoirs Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at a depth of 10,000 feet, the pressure is considered to be normal.
Over-pressured reservoirs Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.
Plant products Liquids generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.
Plugging and abandonment or P&A Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
PV10% The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices, as prescribed in the SEC rules, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using and annual discount rate of 10%. PV10% is considered a non-GAAP financial measure as defined by the SEC.
Primary recovery The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.
Productive well A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed nonproducing reserves or PDNP Proved developed nonproducing reserves are proved reserves that are either shut-in or are behind-pipe reserves.
Proved developed producing reserves or PDP Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.
Proved developed reserves Proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.
Proved reserves The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped location A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUD Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
Re-engineering a process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.
Reprocessing Taking older seismic data and performing new mathematical techniques to refine subsurface images or to provide additional ways of interpreting the subsurface environment.
Reservoir A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
SEC The U.S. Securities and Exchange Commission.
Secondary recovery The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.
Shut-in reserves Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed.
Standardized Measure of Discounted Future Net Cash Flows Present value of proved reserves, as adjusted to give effect to estimated future abandonment costs, net of estimated salvage value of related equipment, and estimated future income taxes.
3-D seismic An advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
Undeveloped acreage Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Waterflooding The secondary recovery method in which water is forced down injection wells laid out in various patterns around the producing wells. The water injected displaces the oil and forces it to the producing wells.
Working interest or WI The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and share of production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development operations and all risks in connection therewith.
Workover Operations on a producing well to restore or increase production.
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 areas of the United States. 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.
Our strategy, which is further discussed below, calls for operations in multiple basins and also includes a combination of acquisition, development and exploration activities. Management believes, this approach allows us to manage risk and also take advantage of changing market conditions and regional differences in commodity pricing and costs and available infra-structure. At present our exploration and development activities are principally focused on the development of our acreage positions in the Bakken shale trend in the Williston basin and the Eagle Ford shale trend in Texas. In these two areas, at present we hold 44,000 net acres and 21,000 net acres, respectively.
As of January 1, 2011, we had an estimated 23,985 MBOE of proved reserves being approximately 60% oil and 74% developed. Production for the year ended December 31, 2010 totaled 1,858 MBOE or 5,090 BOE per day of which 57% was oil. In addition, we have a general partner and operating interest in two managed limited partnerships, which are accounted for on the equity method. Our share of partnership reserves, at January 1, 2011 were estimated at 1,361 MBOE, being 96% natural gas and 89% developed. See Item 2 of this report for additional information related to our oil and gas reserves at January 1, 2011.
Acquisition and Divestitures
During 2010 we continued our drilling programs and expanded our acreage positions. We also acquired producing and undeveloped properties, principally in the Bakken Shale trend in the Williston Basin, North Dakota and in the Giddings field, Texas. A summary of our 2010 activities is as follows:
On July 13, 2009, we entered into a Second Amended and Restated Credit Agreement (Second Amended Credit Agreement), which increased our previous credit facility from $200 million to $250 million and extended the term of the agreement to October 16, 2012. The initial borrowing base of the facility was $135 million, subject to redetermination on May 1 and November 1 of each year. On November 9, 2009 the borrowing base was increased to $145 million. The Second Amended Credit Agreement provides for interest rates at (a) LIBOR plus 2.25% to 3.00% or (b) the prime lending rate plus 1.25% to 2.00%, depending upon the amount borrowed and also requires the payment of commitment fees to the lender in respect of the unutilized commitments. The commitment rate is 0.50% per annum. We incurred costs of approximately $2.5 million to complete the amendment and we are amortizing these costs over the remaining life of the Second Amended Credit Agreement; the amortization is included in interest expense. The participating banks include: Wells Fargo Bank; Comerica Bank; BBVA Compass; U.S. Bank; Frost National Bank; Bank of Texas and Natixis. In January 2011, we paid all of our outstanding debt.
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 shares. The warrants have a term of five years ending June 5, 2013, with an exercise price $32.43 per share. The net proceeds of the offering were $32.2 million.
On December 1, 2009, we issued 3,450,000 shares of our common stock at $10.20 per share to investors pursuant to an offering registered with the SEC. The closing included the exercise in full of the underwriters over-allotment option. Net proceeds from the offering were approximately $33.1 million after deducting the underwriters discount and other offering expenses, and were used to reduce outstanding indebtedness under our Second Amended Credit Agreement.
On January 19, 2011, we issued 5,175,000 shares of common stock and 989,000 shares were sold by certain selling shareholders, at a price to the public of $25.00 per share. Net proceeds to the Company from the offering were approximately $122.9 million after deducting the underwriters discount and other offering expenses, and were used to reduce our outstanding indebtedness under our Second Amended Credit Agreement of $87 million. We anticipate that the remaining net proceeds will primarily be used to fund drilling and development expenditures.
Our Business Strategy
Our strategy includes a combination of acquisitions, development and exploration activities, currently focused primarily on oil projects in the Bakken trend in the Williston Basin of North Dakota and Montana and in the Eagle Ford trend in Texas. We focus on building production, reserves and cash flows and continually work to expand our undeveloped acreage and drilling inventory as well as our high-grade assets. Historically, we have shifted our emphasis among these basic activities to take advantage of changing market conditions to facilitate profitable growth.
Our business strategy includes:
Our fundamental operating and technical strategy is complemented by managements commitment to increasing shareholder value by:
In the opinion of management, our strategy is appropriate for us because:
Each component of our business strategy and related matters are briefly discussed below.
Acquisitions and Divestitures The fundamental intent of our acquisition and divestiture activities is to continually high-grade our property portfolio. Such acquisitions of oil and gas producing or undeveloped properties, either through corporate or asset acquisitions, is 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 important part of our post-acquisition activities associated with producing properties are re-engineering projects intended to implement more efficient production practices, increase production or arrest production declines, lower per-unit operating expenses and/or reduce field down-time. Our producing properties include certain non-core legacy properties that are providing production and cash flows to pursue other opportunities. Consistent with our growth and in order to devote our human resources toward our most significant projects, periodically we will divest non-core assets.
Development Activities The largest part of our capital expenditures relates to the development and exploitation of non-producing reserves and development/expansion of our core acreage positions. In our core areas, we conduct comprehensive regional geological and geophysical studies and detailed field studies of existing properties which usually result in identifying:
Exploration Our exploration activities are intended to provide significant upside potential; accordingly, we expect to continue to expand our exploration activities as our asset base increases. This strategy is designed to:
Corporate Mergers and Acquisitions As a distinct part of our overall strategy, we continue to pursue corporate merger and acquisition opportunities as a means to increase shareholder value. Criteria for such acquisitions might include, but are not limited to:
In summary, we believe our business practices and methodical processes will maintain our reserve and production base and lead to growth in reserves, production, cash flow and consequently, in per share values.
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 the spot market for gas sold in the area.
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 in this report, we have entered into long-term commodity hedge contracts to mitigate the effects of price declines of oil and natural gas.
In addition to being highly speculative, the domestic 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 more for desirable properties or more effectively exploit productive prospects due to their size and ability to secure better service contracts.
We conduct our operations according to high industry standards and in full compliance with all applicable 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.
As of December 31, 2010, we had 60 full-time employees, 42 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. We have no unions and are not the subject of any collective bargaining agreements.
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.
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 that are not presently known to us, or that we presently deem immaterial, may become material and 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. See Forward Looking Statements at the beginning of this report for additional risks.
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.
The domestic oil and gas exploration and production industry is faced with shortages of personnel and equipment, and such shortages may adversely affect our operations and financial results.
The oil and gas industry, as a whole, suffers from an aging workforce and a 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 operations. Further, our expansion plans will likely require access to services and oil field equipment. Such equipment and operating personnel are currently in short supply. The substantial increase in commodity prices in 2010 has resulted in increased drilling and construction activity in the industry and shortages of personnel and equipment are present in our primary areas of focus the Williston Basin in North Dakota and the Eagle Ford trend in Texas.
The unavailability of drilling rigs and field services in the Bakken trend in North Dakota and the Eagle Ford trend in Texas could adversely affect our ability to execute our development plans within our budget on a timely basis.
Existing shortages of drilling rig service providers for pressure pumping and other services required for well completion in the Bakken trend in North Dakota and Montana and the Eagle Ford trend in Texas have delayed our development and production operations and caused us to incur additional expenditures that were not provided for in our capital budget. We cannot determine the magnitude or length of these shortages, but they could have a material adverse effect on our business cash flows, financial condition or results of operations.
We may experience significant delays between drilling and completion on both our operated and non-operated properties in the Bakken trend and the Eagle Ford trend.
Industry-wide delays between drilling and completion operations in Bakken trend and the Eagle Ford trend may continue to increase. Increased delays could delay or adversely affect our exploration, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.
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:
Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.
Our most significant market risk is the pricing of crude oil and natural gas. Management expects energy prices to remain volatile and unpredictable. Moreover, oil and natural gas prices depend on factors that are outside of our control, including:
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. We have attempted to mitigate the risks associated with commodity price fluctuations by hedging a portion of production through price swaps and costless collars. However, substantial or extended declines in oil or natural gas prices may still 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 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:
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:
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.
We have hurricane associated risks in connection with our operations in the Texas and Louisiana Gulf Coast.
We have experienced in the past significant production curtailments due to hurricane damage. We could also be subject to production curtailments in the future 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.
Insurance may not fully recover potential losses.
Although we believe that we are reasonably insured against losses to wells and associated equipment, potential operational or hurricane related losses could result in a loss of our reserves and properties and materially reduce the funds available for exploration and development activities and acquisitions. The insurance market, in general, and the energy insurance market in particular, have experienced substantial cost increases over recent years, resulting from significant losses associated with hurricanes and commercial losses. To offset the significant cost
increases we have increased our deductibles and made other modifications to coverage. We believe these changes are reasonable, considering both the underlying risks and our size and financial standing. The potential for loss, however, cannot be accurately or reasonably predicted. If we incur substantial damages or liabilities that are not fully covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition could be materially affected. Also, as is customary in the oil and gas business, we do not carry business interruption insurance. In the future, it is also possible that we will further modify insurance coverage or determine not to purchase some insurance because of high insurance premiums.
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 fields 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.
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 our 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.
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.
The recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) is comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing certain portions of it by mid-July 2011. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt similar rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower the commodity prices we realize. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
The use of debt financing may adversely affect our business strategy.
We have used debt to fund a portion of our 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.
We are obligated to comply with financial and other covenants in our existing Second Amended Credit Facility that could restrict our operating activities, and the failure to comply could result in defaults that accelerate the payment of our debt.
Our Second Amended Credit Facility generally contains customary covenants, including, among others, provisions:
In addition, our Second Amended Credit Facility requires us to maintain financial covenants, including, but not limited to the following:
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 immediately repay any outstanding debt amounts at the time, 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.
Global financial and economic circumstances may have impacts on our business and financial condition that we currently cannot predict.
Global financial markets may have an adverse impact on our business and our financial condition, and we may face challenges if conditions in the financial markets are inadequate to finance our activities at a reasonable cost of capital. While the current economic situation has improved since 2008 any deterioration in financial markets (or changes in lending practices) could have a material adverse impact on our lenders. Furthermore, adverse economic circumstances could cause customers, joint owners or other parties with whom we transact business 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, worldwide economic conditions could lead to 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.
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 owners 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 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 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.
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.
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; and 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, as well as how such laws and regulations are administered, 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. In recent years, increased concerns have been raised over the protection of the environment. Legislation to regulate the emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects.
Climate change legislation or regulations restricting emissions of greenhouse gasses could result in increased operating costs and reduced demand for oil and gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earths atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, effective as of when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting programs. This rule tailors these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to best available control technology standards for GHG that have yet to be developed. In addition, on November 8, 2010, the EPA adopted the final rule which expands its existing GHG reporting rule to include certain onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. The final rule is effective as of December 30, 2010 and requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Our operations will likely be subject to the latter rule.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and more than one-third of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations and could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have in an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.
Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations to stimulate hydrocarbon (oil and natural gas) production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with several wells or proposed wells for which we are the operator. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Bakken and the Eagle Ford, where we have significant acreage. The process is typically regulated by state oil and gas commissions. However, Congress recently has considered two companion bills in connection with the proposed Fracturing Responsibility and Awareness of Chemicals Act (the FRAC Act). While now not under consideration by Congress, if reintroduced, the bills would repeal an exemption in the Federal Safe Drinking Water Act (SWDA) for the underground injection of hydraulic fracturing fluids near drinking water sources and require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process may be adversely impacting drinking water supplies. If reintroduced, the legislation would require the reporting and public disclosure of chemicals used in the fracturing process. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Further, if reintroduced and enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. In addition, the Energy and Commerce Committee of the United States House of Representatives is conducting an investigation of hydraulic fracturing practices.
Recently, the U.S. Environmental Protection Agency (EPA) asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SWDAs Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPAs recent decision. On February 8, 2011, the EPA submitted its draft study plan on the effects of hydraulic fracturing on human health and the environment to the EPAs Science Advisory Board for comment. Thereafter, the EPA will revise and begin the study. The EPA expects to make public its initial findings by the end of 2012 and an additional report with further research in 2014. Further, the agency has announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector, and has already commenced one potential enforcement matter in Texas. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and also to attendant permitting delays and potential increases in costs.
In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can economically produce. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities on a timely basis following leasing. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.
Our failure to successfully identify, complete and integrate future acquisitions of properties or business 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.
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Even if our credit reviews work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could adversely affect our business.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to economically produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our natural gas and oil reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue making substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed, and in the future we intend to continue to finance, capital expenditures primarily with cash generated by operations, proceeds from bank borrowings, including under existing facilities, and sales of equity securities. Our cash flow from operations and access to capital are subject to a number of variables that may or may not be within our control, including:
If our revenues or the borrowing base under our credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our credit facility restricts our ability to obtain new debt financing outside that facility. There can be no assurance as to the availability or terms of any additional or alternative financing.
If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing on acceptable terms could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to possible writedowns in the carrying value of our properties, a decline in our natural gas and oil reserves as well as our revenues and results of operations.
Changes in financial markets could result in 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. Financial markets often change abruptly and 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.
Effects of inflation and pricing may impact our demand for goods 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. Demand for equipment and services have caused costs to increase significantly throughout 2009 and 2010. 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 our 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.
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 25,420,842 shares of our common stock outstanding as of March 10, 2011. Members of our management owned approximately 5,597,959 shares of our common stock, representing 22% of our outstanding common stock as of March 10, 2011. Sale of a substantial number of these shares would likely have a significant negative effect 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 shareholders, 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 have a depressing effect on the market price of our shares.
Our principal offices are located at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, where we occupy approximately 15,800 square feet of office space. Our Northern Region office, consisting of approximately 5,000 square feet, is located at 475 17th Street, Suite 1210, Denver, Colorado 80202. Our Williston office consists of approximately 4,000 square feet and is located at 1407 West Dakota Parkway, Williston, North Dakota 58801.
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 reserve estimates have been prepared by 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 January 1, 2011. We did not provide any reserve information to any federal agencies in 2010 other than to the SEC.
Oil and Gas Reserve Quantities
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 - Unaudited in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. The table below (Non-GAAP Reconciliation) provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.
Partnership Operations and Reserves as of January 1, 2011 (not included above):
The reserve quantities and values set forth above do not include our interest in two affiliated partnerships.
We hold a 30% partnership interest in SBE Partners, LP (SBE Partners) which owns interests in the Giddings field (as discussed further below in Description of Noteworthy Properties). In addition, we hold direct working interests in producing oil and gas properties located throughout Oklahoma and we also hold the general partner interest in OKLA Energy Partners, LP (OKLA) which owns a larger interest in those same producing oil and gas properties. Our 2% partnership interest in OKLA reverts to 35.66% if the limited partner realizes a contractually specified rate of return.
The following table represents our estimated share (excluding our reversionary interests) of the affiliated partnerships reserves and estimated present value of future net income discounted at 10% (in thousands), using SEC guidelines.
The following table reconciles our direct interest in oil and gas reserves (in thousands):
The following table reconciles our indirect interest, through our affiliated partnerships, 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.
Proved Undeveloped Reserves
From January 1, 2010 to January 1, 2011, our proved undeveloped reserves (PUDs) increased 23% from 5,081,000 BOE to 6,238,000 BOE, or an increase of 1,157,000 BOE. This increase was attributable primarily to successful drilling activity and property acquisitions made during 2010 in the Bakken Shale trend of North Dakota and the Giddings field in Texas. We added 956,000 BOE as a result of successful drilling in 2010 and the commensurate PUDs associated with such drilling. As a result of acquisitions during 2010, we added 76,000 BOE. There were zero BOE that were no longer deemed to be economic PUDs at year-end. Reserves of 972,000 BOE were moved from the PUD reserve category to the proved developed category through the drilling of 35 gross wells. We incurred approximately $11.7 million in capital expenditures during 2010 in converting these 35 gross PUD wells to the proved developed reserve category. The remaining change in PUDs of 1,097,000 BOE was a result of increased prices and performance revisions over the time period. Based on our 2010 year end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within five years.
Preparation of Reserve Estimates
We have engaged an independent petroleum engineering consulting firm, Cawley Gillespie & Associates, Inc. (CG&A), to prepare our annual reserve estimates and have relied on their expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is Mr. Robert Ravnaas, Executive Vice President at CG&A. He earned a Bachelors of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder in 1979, and a Masters of Science degree in Petroleum Engineering from the University of Texas at Austin in 1981. Mr. Ravnaas is a Registered Professional Engineer in Texas and has more than 30 years of experience in the estimation and evaluation of oil and gas reserves. He is also a member of the Society of Petroleum Geologists, and Society of Professional Well Log Analysts.
Our Executive Vice President, Engineering and Acquisitions, who is a qualified reserve estimator and auditor, is primarily responsible for overseeing our independent petroleum engineering firm during the preparation of our reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelors of Science degree in Petroleum Engineering from the University of Wyoming, 1986; Masters of Business Administration degree from University of Denver, 1988; member of the Society of Petroleum Engineers since 1985; and more than 23 years of practical experience in estimating and evaluating reserve information with more than five years of those being in charge of estimating and evaluating reserves.
We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest, and production data. The relevant field and reservoir technical information, which is updated annually, is assessed for validity when our independent petroleum engineering firm has technical meetings with our engineers, geologist, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified
internally by us to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, our independent engineering firm meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to our internal estimates by our Executive Vice President, Engineering and Acquisitions and staff in our reservoir engineering department. Material reserve estimation differences are reviewed between CG&As reserve estimates and our internally prepared reserves on a case-by-case basis. An iterative process between CG&A and us regarding any significant differences allows for additional data to be provided in order to address the differences. If the supporting documentation will not justify any additional changes, the CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make any changes it deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A. Access to our reserve database is restricted to specific members of our reservoir engineering department.
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 years ended December 31, 2010 the average sales price per unit sold and the average production cost per unit are presented below.
Our oil 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. Natural gas liquids have been converted to Mcf in the table above.
In 2010, two purchasers each accounted for 12% of our consolidated oil and gas revenues and one purchaser accounted for 11%. In 2009, one purchaser accounted for 17% of our consolidated oil and gas revenues, two purchasers accounted for 15% each of our consolidated oil and gas revenues, and one more accounted for 11%. In 2008, one purchaser accounted for 16% of our consolidated oil and gas revenues, two more accounted for 11% each and two purchasers accounted for 10% each of our consolidated oil and gas revenues. No other single purchaser accounted for 10% or more of our oil and gas revenues in 2010, 2009 or 2008. 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, 2010, our total gross and net productive wells were as follows:
Productive Wells *
Gross and Net Developed and Undeveloped Acres
As of December 31, 2010, 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 or permitted 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, 2010 is information concerning the number of wells we drilled during the years indicated.
At March 10, 2011, we had 61 gross (3.95 net) wells in the process of drilling or completing.
Supply Contracts or Agreements
As of December 31, 2010, we were 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. We also engage in hedging activities as discussed in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Description of Noteworthy Properties
We are the operator of properties containing approximately 75% of our proved oil and gas reserves. As operator we are able to directly influence exploration, development and production operations. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations, and thus provide a foundation for our technical staff to pursue the development of our undeveloped acreage, further develop our existing properties and also generate new projects that we believe have the potential to increase our share value. Although, we believe that many of our existing fields have additional exploration and exploitation opportunities, these opportunities are held by continuing production operations and therefore we have deferred certain projects in favor of development drilling associated with our Bakken and Eagle Ford shale, as further discussed below. As common in the industry we participate in non-operated properties on a selective basis; our non-operating participation decisions are dependent on the technical and economic nature of the projects and the operating expertise and financial standing of the operators. The following is a description of certain of our noteworthy operated and non-operated producing oil and gas properties.
Bakken Shale and Three Forks Formations, Williston Basin Overview We believe the Bakken Shale and Three Forks formations in the Williston Basin represent a large North American oil deposit. A report issued by the United States Geological Survey, or USGS, in April 2008 classified the Bakken formation as the largest continuous oil accumulation ever assessed by it in the contiguous United States. Our Williston Basin, Bakken Shale properties are located primarily in Mountrail and Williams Counties, North Dakota and in Roosevelt and Richland Counties, Montana. We presently have working interests in approximately 44,000 net acres of which, 24,000 net acres are in Williams County, 11,000 net acres are in Mountrail County and 9,000 net acres are in Roosevelt and Richland Counties. As further discussed below, we have been involved in a non-operated joint venture with Slawson Exploration Company (Slawson) primarily in Mountrail County North Dakota, since 2007. Drilling activities in this joint venture increased appreciably over 2009 and 2010. Consistent with our operating strategy, during 2009 and 2010, we assembled acreage positions in Williams County, North Dakota and in Eastern Montana. At present, we anticipate operating the majority of spacing units across our acreage, outside of Mountrail County, and we continue to lease or otherwise acquire or trade for acreage within these project areas. At present we are running one rig in Williams county and eastern Montana and plan to bring on a second and third rig during 2011 depending on drilling rig availability.
Williams County, North Dakota - Our Williams County project area is comprised of 24,000 net acres, representing a 47.5% working interest where we have lease positions in eighty-two 1,280 acre spacing units. We originated the project and brought in industry partners on a promoted basis. We retained operations within a specified area of mutual interest. Drilling began in the project area in late 2010. We have drilled three operated wells and participated on one non-operated well. These wells are all in varying stages of completion and production operations.
Roosevelt and Richland Counties, Montana - In eastern Montana, we have acquired approximately 9,000 net acres where we are the operator of sixteen 1,280 acre units and have non-operated interests in several additional units. To date we have participated in three non-operated units, two of which are producing and the other one is waiting on hydraulic fracturing. We have also initiated our operated drilling program where we have drilled with the
Wheeler Ranch 9-16, which is a vertical Ratcliffe proved undeveloped location awaiting completion and we are currently drilling our first middle Bakken well.
Bakken Non-Operated Joint Venture, North Dakota - Our principal drilling activities in our Bakken non-operated joint venture are conducted through Slawson Exploration Company, Inc., but we also participate in this area with several other industry participants. We have varying working interests in the 11,000 net acres ranging from 10% to 18% in Montrail and nearby counties. To date, over 80 joint venture wells have been drilled by Slawson and we also have nominal interests in over 240 wells with other operators that are producing or are in various stages of drilling and completion. For the quarter ended December 31, 2010, the total production net to our interest in the Bakken trend was approximately 1,171 BOE/day and was approximately 93% oil.
Other Williston Basin Fields - We also operate other fields in Montana and North Dakota, including the Fairview, Fort Gilbert and Mondak Fields in Richland County, Montana, the Froid South Field in Roosevelt County, Montana and the Starbuck Madison Unit, Southwest Starbuck Field, the Landa, Northeast Landa, Sherman and Wayne Fields in Bottineau County, North Dakota. The Montana fields are comprised of 12 gross producing wells from the Mission Canyon interval through the Red River interval. We have an average working interest of 72% with a 61% net revenue interest in these fields. The Froid area has become prospective for Bakken formation production with recent well activity in the area and we control five potential 1,280 acre drilling units and have working interests in two possible additional drilling units. The Sherman/Wayne Fields consist of 20 gross producing wells, which produce from the Mississippian Wayne interval. We have an average working interest in the fields of 80%, with an average net revenue interest of 70%. The Landa/Northeast Landa area has 15 gross producing wells from the Spearfish and Madison intervals. We have a 92% average working interest and a 78% average net revenue interest in these wells. The Starbuck Madison Unit and Southwest Starbuck Field have been unitized and water-flood operations are underway. We operate the units and at the Starbuck Madison Unit have an average working interest of approximately 96% and an average net revenue interest of 81%. At Southwest Starbuck, we have a 98% working interest and a 75% net revenue interest. These two water-floods had production net to our interest of 59 BOE/day (100% oil) for the quarter ended December 31, 2010. For the same period, the production net to our interest in the remaining Williston Basin Fields, including those mentioned above but excluding the Bakken and Starbuck areas, was approximately 405 BOE/day (93% oil).
Eagle Ford Shale Trend - Our Eagle Ford properties are located in Atascosa, Fayette, Gonzales and McMullen counties of Texas. In southwest Fayette County, we have entered into agreements with an industry partner, which established an area of mutual interest, resulted in a cash payment of $20 million for a 50% undivided interest in our acreage, provides for the drilling and completion of six wells, where we retain a 50% interest, without cost to us and further provides us with a retained overriding royalty interest. The agreement also provides for additional leasing. Our net acreage position in the Eagle Ford Trend totals approximately 21,000 acres. Our initial drilling unit is the 900 acre Flatonia East Unit, located in southwest Fayette County, Texas. We have drilled and cased our initial well in the unit and are currently drilling the second unit well. We have a 50% working interest in this drilling unit and we are the operator for the entire project. Our net working interests in our Eagle Ford acreage range from 32.5% to 65%.
Giddings Field - Our Giddings Field properties are located in Brazos, Burleson, Fayette, Grimes, Lee, Montgomery and Washington Counties, Texas. We operate all but two of these properties, which consist of 68 gross wells that are producing from the Cretaceous Austin Chalk interval. All of the wells are horizontal producers that initially flow at high rates and subsequently produce through rod pumps, compression, and other production methods. We have an average direct working interest of 36% and an average net revenue interest of 28% in this field. In addition, we are the general partner and 30% owner of a limited partnership that owns an average 56% working interest with an average 43% net revenue interest in the Giddings Field. Our acreage position is 35,804 net acres, with approximately 29,406 net acres held directly and approximately 6,398 net acres held through our interest in the limited partnership. From 2007 to early 2010, when we suspended our drilling operations due to low gas prices, we drilled 16 wells with a 100% success rate. We have 20 remaining Austin Chalk drilling locations and believe the acreage is prospective for the Yegua, Georgetown and Eagle Ford formations. Production from the Giddings Field is primarily gas and for the quarter ended December 31, 2010, the production net to our interest in the Giddings Field was approximately 7,440 Mcfe/day and was approximately 96% gas. An additional 2,479 Mcfe/day (96% gas) was attributable to our share of the limited partnership. Our 2010 acquisition in Giddings and nearby fields was located primarily in Brazos and Madison counties, Texas. This property consists of 40 producers with all but three
being operated by the Company. Production is from horizontal and vertical wells in the Austin Chalk, Buda and Woodbine formations. Our average working interest is 44% with an average net revenue interest of 32%. We are evaluating the acreage for possible Austin Chalk and Woodbine drilling opportunities. For the quarter ended December 31, 2010 our net production from these properties was approximately 252 BOE/day (77% oil).
St. Martinville Field - Our St. Martinville Field is located in St. Martin Parish, Louisiana. The field consists of 12 gross producing wells, which produce from numerous Miocene sand intervals. The wells are on rod-pump or electric submersible pumps. We operate the field and have an average working interest of 97%. We own the majority of the minerals resulting in a net revenue interest of approximately 91%. The Conoco Fee A-53 was drilled and completed during the fourth quarter of 2010 and commenced production in early 2011. We continue to work the 3-D seismic and subsurface geologic well control and expect to identify additional drilling locations. For the quarter ended December 31, 2010, the production net to our interest in this field was approximately 137 BOE/day (100% oil).
Eloi Bay Field Complex - Our Eloi Bay complex is located in Louisiana state waters offshore St. Bernard Parish, Louisiana in five to 10 feet of water. This non-operated complex has 54 gross producing wells. Our working interests in these wells vary between 12% and 50%. Across the complex as a whole, our average working interest is 46% and our average net revenue interest is 39%. For the quarter ended December 31, 2010, the production net to our interests in the complex was approximately 372 BOE/day (100% oil).
Quarantine Bay Field - Our Quarantine Bay Field is located in Louisiana State waters offshore Plaquemines Parish, Louisiana in six to 15 feet of water. The majority of field pay zones have been developed at depths above 10,500 feet. At present, the field has 32 gross producing wells. We have an average working interest in these wells of 7% and an average net revenue interest of 5%. However, we have a 33% working interest in deeper potential which are generally below 11,500 feet but are further defined in assignments. Our smaller working interest in the shallow production provides cost effective access to production facilities. We believe significant exploration potential exists below field pays. For the quarter ended December 31, 2010, the production net to our interest in this field was approximately 42 BOE/day (99% oil).
South Texas Our south Texas fields include the Odem Field, located in San Patricio County; the Driscoll Field, located in Duval County; and the Chittim Ranch Field, located in Maverick County. Productive formations include the Frio/Miocene, Jackson/Yegua and Glen Rose intervals. The fields produce with the aid of rod pumps, gas lift and low pressure gathering systems. We operate these fields and our working interests in them range from 44% to 98% and our net revenue interests range from 35% to 86%. For the quarter ended December 31, 2010, the production net to our interest in these fields was approximately 445 BOE/day (43% oil).
West Texas Our west Texas and New Mexico fields include our Harris Field, located in Gaines County, Texas; our MAK Field, located in Andrews County, Texas; and other fields located in Eddy and Lea Counties, New Mexico. Productive formations include the San Andres, Spraberry, Seven Rivers, Queen and Grayburg intervals. The fields produce with the aid of rod pumps. We operate these fields and our working interests in them range from 68% to 100% and our net revenue interests range from 52% to 78%. For the quarter ended December 31, 2010, the production net to our interests in these properties was approximately 235 BOE/day (79% oil).
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. Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources).
We are not party to, nor are any of our properties subject to, any material pending legal proceedings. We know of no material legal proceedings contemplated or threatened against us.
Executive Officers of the Registrant
The following table sets forth certain information as of March 10, 2011, regarding the executive officers of GeoResources, Inc.:
Frank A. Lodzinski has been President, Chief Executive Officer and Director of the Company since 2007. He has 40 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 late 2005 acquired certain assets from AROC. Southern Bay was merged into GeoResources in April 2007 (Merger). Mr. Lodzinski holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan and is a Certified Public Accountant.
Robert J. Anderson is Executive Vice President, Engineering and Acquisitions. He has been employed by the Company since April 2007. He is a Petroleum Engineer and has been active in the oil and gas industry since 1987 with diversified domestic and international experience for 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. Andersons 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).
Collis P. Chandler, III has been Executive Vice President and Chief Operating Officer - Northern Region and Director of the Company since April 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.
Howard E. Ehler is our Chief Financial Officer and Principle Accounting Officer and has been employed by the Company since April 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.
Francis M. Mury has been Executive Vice President and Chief Operating Officer - Southern Region of the Company since April 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.
Our common stock trades on The NASDAQ Global Select Market under the Symbol GEOI. The following table sets forth, for each of the periods indicated, the high and low sales prices per share of our common stock as reported by The NASDAQ Global Select Market. These trade prices may represent prices between dealers and do not include retail markup, markdowns or commissions.
As of March 10, 2011, there were approximately 550 holders of record of our common stock. We believe that there are also approximately 8,000 additional beneficial owners of our common stock held in street name.
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 future cash 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.
Equity Compensation Plan Information
The following sets forth information as of March 10, 2011, concerning our compensation plan under which shares of our common stock are authorized for issuance.
The following selected financial data contained in this table should be read in conjunction with Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations, and our consolidated financial statements and the accompanying notes thereto included elsewhere in this report.
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.
We are an independent oil and gas company engaged in the acquisition, development and production of oil and gas reserves in multiple basins. As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to 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.
Our strategy includes a combination of acquisition, development and exploration activities. Historically, we have shifted our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our oil-weighted acreage positions in the Bakken trend of Montana and North Dakota and the Eagle Ford trend of Texas. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so we have the potential of economically replacing our production and increasing our proved reserves. Following is a brief outline of our current plans:
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 pursue corporate acquisitions and mergers. We believe that a corporate acquisition or merger could potentially accelerate growth, increase market visibility and realize operating and administrative benefits. Accordingly, we intend to consider any such opportunities which may become available that we consider beneficial to our stockholders. The primary financial considerations in the evaluation of any such potential transactions include, but are not limited to: (1) the potential to increase assets in a core area, (2) the opportunity to increase our earnings and cash flow on a per share basis, (3) development and exploration potential, and (4) realization of administrative savings. Further, we believe a corporate acquisition could lead to increased visibility in the market place, greater trading volume and therefore greater shareholder liquidity and possibly access to capital with lower costs.
Recent Property Acquisitions
During 2010 we continued our drilling programs and expanded our acreage positions. We also acquired producing and undeveloped properties, principally in the Bakken Shale trend in the Williston Basin, North Dakota and in the Giddings field, Texas. A summary of our 2010 activities is as follows:
Results of Operations
Year ended December 31, 2010, compared to the year ended December 31, 2009.
We realized net income of $23.3 million and $9.8 million for the years ended December 31, 2010, and 2009, respectively. The $13.6 million increase in net income resulted primarily from the following factors.
The following discussion applies to the above changes.
Oil and Natural Gas Sales. Oil and gas revenues increased by $28.3 million, or 40%. Increased commodity prices accounted for $16.1 million of the increase and increased production volumes accounted for the remaining $12.2 million. Increased oil production was attributable primarily to new wells drilled during 2010 and 2009, as well as recent acquisitions, partially offset by normal production declines on previously existing wells. Price and production comparisons are set forth in the following table.
Lease Operating Expenses - Lease operating expenses (LOE) increased from approximately $18.8 million for 2009 to $20.9 million for 2010, an increase of $2.2 million or 12%. Our lease operating expenditures have increased primarily due to increased production; on a unit-of-production basis, LOE costs have slightly increased by $.07 per BOE to $11.27 per BOE.
Re-engineering and workover - Re-engineering and workover costs decreased from $2.8 million to $2.0 million primarily due to a major re-engineering and workover program concluded in 2009.
Production Taxes - Production taxes increased by $2.4 million or 57%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for 2010 and 2009 were 6.6% and 6.5%, respectively, of oil and gas sales before the effects of hedging.
Exploration and Impairment Costs - Our exploration costs were $849,000 for December 31, 2010 and $1.4 million for 2009. We incurred residual costs of $192,000 during 2010 on an exploratory well deemed to be a dry hole prior to December 31, 2009. The remaining $657,000 were geological and geophysical costs. In 2009, we incurred $1.3 million for geological and geophysical data and incurred dry hole and other costs of $83,000. We recorded non-cash impairments charges of $3.4 million and $2.8 million in 2010 and 2009, respectively, due to the write-down of proved properties. The book value of these properties exceeded our estimate of future undiscounted cash flows as a direct result of the decline in our estimate of future natural gas prices.
General and Administrative Expenses - Our G&A costs increased from $8.5 million in 2009 to $9.5 million in 2010, an increase of $1.0 million, or 11% as a result of increases in salaries and other overhead expenses offset by a decrease in non-cash charges related to our stock-based compensation.
Depreciation, Depletion and Amortization - DD&A expense increased by $2.3 million or 10% due to higher capitalized costs and higher production. Capitalized costs increased due to acquisitions of additional property interests in both the Giddings field and Bakken Shale and continued successful drilling in the Bakken. On a units-of- production basis, DD&A per BOE decreased slightly from $13.38 in 2009 to $13.29 in 2010.
Interest Income and Expense - Interest expense decreased by $272,000 due to capitalized interest. We capitalized interest of $234,000 in 2010 and none in 2009. Our average outstanding debt was $73.6 million and $74.2 million during 2010 and 2009, respectively. The effective annual interest rate was 6.7% for 2010 and 2009. The interest rates reflect the effects of interest swap contract settlements, as well as loan fees. Interest income decreased by $448,000 during 2010 compared to 2009 due to $415,000 of interest earned on severance tax refunds in 2009 and none in 2010.
Hedge Ineffectiveness - During 2010 the gain from hedge ineffectiveness was $891,000, compared to a loss of $137,000 for 2009. The ineffectiveness in 2010 relates to our gas derivatives accounted for as a cash flow hedges, which increased in value. The change in the ineffective portion of these derivatives was a gain. During 2009, our derivatives accounted for as cash flow hedges decreased in value; therefore, the change in the ineffective portion of these derivatives was a loss.
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. These swap contracts expired in October 2010. We recognized gains of $2,000 in 2010 and losses of $162,000 in 2009.
Other Income - Other income decreased by $1.4 million in 2010 compared to 2009 due to a decreases in partnership income and partnership management fees, offset by an increase in severance tax refunds. During 2010, we recorded partnership income of $2.2 million and during 2009 we recorded $4.3 million. The 2009 partnership income included $1.3 million of gains on sales of properties to the general partner and $1.3 million of refunds on severance taxes for which the state of Texas granted exemptions. These decreases in partnership income were partially offset by our increased share of revenues and expenses from the partnership. As a result of the property sales, our interest in revenues and expenses from most of the properties in SBE Partners, LP increased from 2% to 30% during the second quarter of 2009. While we expect partnership income to continue to be significant due to our increased interest in SBE Partners we do not expect the partnership to record significant gains similar to those in 2009 on property sales in the future. Since the partnership, subsequent to the sale, held a smaller interest in its properties, our partnership management fee decreased by $457,000.
During 2009 we recorded severance tax refunds of $571,000 on qualifying high cost gas wells in Texas. During 2010 we recorded severance tax refunds of $1.2 million related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana.
Income Tax Expense - Income tax expense for 2010 was $11.9 million compared to $5.1 million for 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate for 2010 and 2009 were 33.82% and 34.14%, respectively. The lower rate for 2010 is attributable to statutory deductions for excess depletion and domestic production activities, both of which represent permanent differences between financial statement income and taxable income.
Year ended December 31, 2009, compared to the year ended December 31, 2008.
We recorded net income of $9.8 million and $13.5 million for the years ended December 31, 2009, and 2008, respectively. The $3.7 million decrease in net income resulted primarily from the following factors.
The following discussion applies to the above changes.
Oil and Natural Gas Sales. Oil and gas revenues decreased $13.6 million, or 16%; however, as shown in the table below, sales volumes increased significantly. Properties acquired from SBE Partners LP in May 2009, increased revenue by $6.5 million and production by approximately 2,122,000 Mcf of gas and 5,000 barrels of oil during 2009. Properties acquired in the May 2009 Bakken acquisition accounted for revenue of $3.7 million and production of approximately 59,000 barrels of oil and 13,000 Mcf of gas during 2009. These increases were offset by significant price declines in the average prices received for oil and natural gas. Price and production comparisons are set forth in the following table:
Lease Operating Expenses - Lease operating expenses (LOE) decreased from approximately $22.9 million for 2008 to $18.8 million for 2009, a decrease of $4.1 million or 18%. On a unit-of-production basis, barrel of oil equivalent (BOE) LOE costs decreased by $7.33 or 40% due primarily to unprecedented demand for oil field services in 2008 which pushed prices for these services to all time highs during 2008, while the prices for these services decreased during 2009. Additionally, we acquired properties in the SBE Partners and Bakken acquisitions with lower per unit operating costs thus further decreasing our lease operating costs on a per unit basis.
Re-engineering and workover - Our re-engineering and workover costs decreased by $711,000, or 20%, from $3.5 million in 2008 to $2.8 million in 2009, due to a cost containment strategy implemented during the lower pricing environment of 2009.
Production Taxes - Our severance taxes decreased by $3.3 million or 44%, due to decreased oil and gas revenues as well as to tax exemptions granted by the state of Texas for certain high cost drilling wells. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We seek to take full advantage of all credits and exemptions allowed in our various jurisdictions. Our production taxes for 2009 and 2008 were 6.5% and 7.9%, respectively, of oil and gas sales before the effects of hedging.
Exploration and Impairment Costs - Our exploration costs were $1.4 million for 2009 and $2.6 million for 2008. In 2009, we incurred $1.3 million for geological and geophysical data and incurred dry hole and other costs of $83,000. In 2008, we drilled four gross exploratory dry holes with costs incurred through December 31, 2008 of $1.9 million, wrote-off undeveloped properties with a cost of $483,000 and incurred geological costs of $161,000. We recorded non-cash impairment charges of $2.8 million and $8.3 million in 2009 and 2008, respectively due to the write-down of proved properties. The book value of these properties exceeded our estimate of future cash flows.
General and Administrative Expenses - Our G&A costs increased from $7.2 million in 2008 to $8.5 million in 2009, an increase of $1.3 million, or 19%. This was due 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. The total non-cash charges related to stock-based compensation included in G&A expense for the years ended December 31, 2009 and 2008 were $1.4 million and $661,000, respectively.
Depreciation, Depletion and Amortization - DD&A increased from $16.0 million in 2008 to $22.4 million in 2009, for an increase of $6.4 million, or 40%. This was due to the substantial increase in capitalized cost attributable to acquisitions, as well as to our active drilling program.
Interest Income and Expense - Interest expense increased by $164,000 due to slightly higher average debt levels during 2009 compared to 2008, partially offset by lower interest rates. Our average outstanding debt was $74.2 million and $67.2 million during 2009 and 2008, respectively. The effective annual interest rates were 6.7% and 7.2%, for 2009 and 2008, respectively. These rates reflect the effects of interest swap contract settlements, as well as loan fees. Interest income decreased by $153,000 during 2009 compared to 2008 due to lower interest rates on average invested cash balances.
Hedge Ineffectiveness - During 2009, the loss from hedge ineffectiveness was $137,000, compared to a gain of $123,000 for 2008. In 2009, our derivatives that are accounted for as cash flow hedges decreased in value from a net asset to a net liability; therefore, the ineffective portion of these derivatives resulted in a loss. In 2008, our derivatives that were accounted for as cash flow hedges increased in value. Therefore, the ineffective portion of the derivatives resulted in a gain.
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 losses of $162,000 and $563,000 in 2009 and 2008, respectively, related to this swap.
Other Income - Other income increased by $3.2 million during 2009 compared to 2008. Partnership income increased by $3.2 million, from $1.1 million in 2008 to $4.3 million in 2009. Gains on sales of properties to the general partner accounted for $1.3 million of this increase and refunds of severance taxes on wells for which the state of Texas granted exemptions accounted for $1.3 million of the increase. The remaining increase in partnership income resulted from our earning a larger share of partnership income.
Income Tax Expense - Our provision for income taxes for 2009 was $5.1 million compared to $7.8 million for 2008. This decrease of $2.7 million was due to lower pretax income, as well as slightly lower rates. Our effective tax rates for 2009 and 2008 were 34.14% and 36.50%, respectively.
Management attempts to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing terms by entering 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 as of March 10, 2010.
The fair market value of our gas hedge contracts in place at December 31, 2010 and 2009, were assets of $5.1 million and $2.1 million, respectively, of which $4.3 million and $764,000 were classified as current assets, respectively. The fair market value of our oil hedge contracts in place at December 31, 2010 and 2009 were liabilities of $9.1 million and $6.4 million, respectively, of which $7.4 million and $3.2 million were classified as current liabilities, respectively. For the year ended December 31, 2010 and 2009, we recognized, in oil and gas revenues, realized cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. Realized hedge settlement losses included in oil and gas revenues were $10.0 million for 2008. Due to hedge ineffectiveness on hedge contracts during 2009 we recognized a non-cash loss of $137,000. During 2010 and 2008, we recognized non-cash gains due to hedge ineffectiveness of $891,000 and $123,000, respectively.
Based on the estimated fair market value of our derivatives, designated as hedges at December 31, 2010, we expect to reclassify net losses on commodity derivatives of $3.2 million into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.
At December 31, 2010, a 10% increase in per unit commodity prices would cause the total fair value liability of our commodity derivative financial instruments to increase by $8.3 million to $12.3 million. A 10% decrease in per unit commodity prices would cause the fair value liability to change to an asset of $4.3 million due to an estimated $8.3 million decrease in the net liability. There would also be a similar increase or decrease in other comprehensive income (loss) included in total 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.
Additionally, should commodity prices increase in the future periods by 10%, our realized settlement losses on commodity derivatives, which are included in oil and gas revenues, would increase by approximately $9.0 million in 2011. If commodity prices decrease in the future by 10%, our realized settlement losses on commodity hedges would decrease by $2.7 million in 2011.
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, designed 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 accounted for the $40 million swap as a cash flow hedge while the $10 million swap was accounted for as a trading security. The value of these swaps at December 31, 2009 was a liability of $1.6 million all of which is classified as a current liability. The value of these swaps at December 31, 2008, was $2.8 million of which $1.6 million was classified as a current liability. We recognized a gain of $2,000 on the $10 million swap during 2010. We also recognized losses of $162,000 and $563,000 during 2009 and 2008, respectively, on the $10 million swap.
Hedging commodity prices for a portion of our production is a fundamental part of our corporate financial management. We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities of our production. In implementing our hedging strategy we seek to:
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. We believe that 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.
Commitments and Contingencies
We have the following contractual obligations and commitments as of December 31, 2010:
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. Our industry has experienced a shortage of such personnel over the past few years, and we expect this shortage to continue as long as oil prices and demand for services in our key operating areas remain at historically high levels.
Liquidity and Capital Resources
We expect to finance future acquisition, development and exploration activities through available 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 debt and or/equity 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 2010 resulted in a net increase in our debt of $18 million from the outstanding debt of $69 million at December 31, 2009. We borrowed $38 million to fund the acquisitions of producing properties and acreage in our Bakken and Eagle Ford areas and made principal debt payments of $20 million. Financing activities during 2009 resulted in a net increase in debt of $29 million from the outstanding debt of $40 million at December 31, 2008. During the second quarter of 2009, we borrowed an additional $64 million to fund the SBE Partners and Bakken acquisitions. During the fourth quarter of 2009, we completed a public offering of common stock and repaid $35 million in debt using the $33 million net proceeds from the stock issue plus $2 million in cash flows from operations.
At December 31, 2010, we had a $145 million borrowing base, with available borrowing capacity of $58 million in accordance with our Amended Credit Agreement with our bank. The borrowing base is redetermined in May and November of each year. As a result of the successful public stock offering in January 2011, we have reduced our outstanding line of credit debt to zero and now have $145 million available under the facility.
Cash Flows From Operating Activities
For 2010, net cash provided by operating activities was $59.5 million, an increase of $35.5 million from 2009. We believe that we can continue to generate cash flows sufficient to allow us to continue with our planned capital expenditures program which will replace our reserves and increase our oil and gas production, assuming
commodity prices do not decrease substantially. For 2009 as compared to 2008, net cash provided by operating activities decreased by $18.3 million. This decrease was directly attributable to the decrease in commodity prices, partially offset by decreases in lease operating expenses, re-engineering and workover expenses and other cost control measures.
Cash Flows From Investing Activities
Cash applied to oil and gas capital expenditures was $82.0 million for 2010, $89.4 million for 2009, and $51.8 million for 2008. In 2010, 2009 and 2008, we realized cash of $1.0 million, $2.0 million and $26.8 million, respectively, from the sale of non-core properties. During 2010, we completed one acquisition for a combined cost of $16.6 million, which was financed with borrowings from our credit facility. During 2009, we completed two acquisitions for a combined cost of $56.7 million. During 2008, we invested $978,000 in newly formed oil and gas limited partnership for which we are the general partner.
Capital Expenditures Budget
We continue to expand our portfolio of drilling and development projects and therefore have increased our projected drilling and development expenditures. As summarized below, we estimate our capital budget for 2011 will total $114.0 million. While the table includes the bulk of our currently identified drilling for 2011, we are constantly working on developing and acquiring new opportunities. A benefit of our property portfolio is that it consists of relatively new acreage positions and therefore we generally have two to five years to drill the bulk of our undeveloped leases. In addition, many of our drilling opportunities, including the bulk of our gas drilling locations, are held by production or long term leases and therefore not subject to lease expiration or significant future incremental carrying costs. Accordingly, we have a substantial ability to adjust our capital spending as industry circumstances dictate or as opportunities arise.
We have initiated drilling on our operated Bakken acreage in the Williston Basin and our operated Eagle Ford acreage in Texas and our Bakken non-operated holdings continue to be actively developed. Those projects represent the bulk of our planned capital expenditures for 2011, as set forth in the table below. However, we may shift our expenditures between geographic areas and projects in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs or other matters we deem of significance.
While industry circumstances may require us to make capital expenditures adjustments, it is our current intent to accelerate our Bakken and Eagle Ford drilling and further expand our acreage. To a lesser extent, we intend to drill certain locations in the Austin Chalk and certain of our prospects on the Gulf Coast, but those projects could be deferred in favor of increased activity in other areas or so long as low natural gas prices prevail.
The projects, estimated costs and timing of actual expenditures are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our portfolio, and as industry conditions dictate. Estimated expenditures are also subject to significant change. There can be no assurance that all of the projects identified and summarized in the table below will remain viable and therefore certain projects may be sold or abandoned by us. However, in the opinion of management, at present, we have sufficient cash flows and liquidity to fulfill lease obligations or otherwise maintain all material mineral leases. Our current estimate of our capital expenditure spending for 2011 is as follows:
Pending success, continuing favorable industry and economic conditions and availability of equipment and services among other factors, our current estimate of capital expenditures for 2012 is approximately $173.0 million, largely directed toward continued Bakken and expanded Eagle Ford drilling and incremental acreage acquisitions.
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 our 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 transaction costs. 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 the FASB. The accuracy of our reserve estimates is a function of:
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 January 1, 2011. 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 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 determines that events and circumstances relating to the significant deterioration in the future cash flow expected to be generated by an asset group indicate that the recorded carrying value of the properties may not be recoverable. This process is performed no less frequently than at the end of each calendar quarter. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net capitalized costs at the end of each period. If the net capitalized costs exceeds undiscounted future cash flows, the cost of the property is written down to fair value, which is determined based on expected future cash flows using discounted rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making relative to acquisitions and divestitures. During 2010, we recorded impairments of $3.4 million on proved properties. These impairments are described in Note A Organization and Summary of Significant Accounting Policies in the notes to the
Consolidated Financial Statements. Different pricing assumptions or discount rates could result in a different calculation of impairment. The significant assumptions used in the current periods calculation are described in Note G Fair Value Disclosures in the notes to the Consolidated Financial Statement. 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 before considering estimated salvage value 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 expenditure 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 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 oil and gas revenues 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 counterpartys 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 counterpartys 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 consolidated 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 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).
We will consider a tax position settled if the taxing authority has completed its examination, we do not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. We use the benefit recognition model which contains a two-step approach, a more likely than not recognition criteria and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, then we will not record the tax benefit. The amount of interest expense that we recognize related to uncertain tax positions is computed by applying the applicable statutory rate of interest to the difference between the tax position recognized and the amount previously taken or expected to be taken in a tax return.
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.
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, these 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.
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, liabilities and non-controlling interests acquired are measured at their fair value including the recognition of acquisition-related costs and anticipated restructuring costs that are separate from the acquired net assets. 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 the fair value of 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 recognized immediately to earnings as a gain from bargain purchase. Certain contingent assets acquired and liabilities assumed in a business combination are recognized at fair value on the acquisition date if we can reasonably estimate a fair value during the measurement period.
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.
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, special purpose entities, financing partnerships or guarantees.
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.
The following is a list of contracts outstanding at December 31, 2010:
We are exposed to financial risk from changes in interest rates. The long-term debt on our balance sheet of $87 million is the outstanding principal amount under our Second Amended and Restated Credit Agreement which matures in October 2012. In the event we have debt outstanding and interest rates were to rise significantly, our interest expense will increase significantly as well, thereby adversely affecting our profitability. At our 2010 debt level, an increase in annual interest rates of 1% would result in an increase in interest expense of $870,000 and a reduction in net income of approximately $576,000.
See Index to Consolidated Financial Statements and Supplementary Information of Page F-1.
(a) Evaluation of Disclosure Controls and Procedures
In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the Exchange Act), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of December 31, 2010. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of December 31, 2010, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.
(b) Managements Report on Internal Control over Financial Reporting
The management of GeoResources, Inc. and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements of external purposes in accordance with generally accepted accounting principles.
Because of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010 using criteria set forth in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes that, as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report which is included herein.
(c) Attestation Report of Registered Public Accounting Firm
Board of Directors and Shareholders of GeoResources, Inc.:
We have audited GeoResources Inc.s (a Colorado corporation) and subsidiaries internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GeoResources, Inc. and subsidiaries management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Managements Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on GeoResources, Inc. and subsidiaries internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
In our opinion, GeoResources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of GeoResources, Inc. and subsidiaries as of December 31, 2010 and 2009 and the related consolidated statements of income, equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010, and our report dated March 11, 2011, expressed an unqualified opinion on those consolidated financial statements.
/s/ Grant Thornton LLP
March 11, 2011
(d) Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The information required by this item is included in our definitive proxy material under the heading Election of Directors and Board of Directors to be filed with the SEC within 120 days after December 31, 2010.
The information required by this item is included in our definitive proxy material under the heading Executive Compensation and Other Transactions to be filed with the SEC within 120 days after December 31, 2010.
The information required by this item is included in our definitive proxy material under the heading Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters to be filed with the SEC within 120 days after December 31, 2010.
The information required by this item is included in our definitive proxy material under the heading Certain Relationships and Related Transaction and Director Independence to be filed with the SEC within 120 days after December 31, 2010.
The information required by this item is included in our definitive proxy material under the heading Independent Public Accountants to be filed with the SEC within 120 days after December 31, 2010.
Form 10-K for the year ended December 31, 2010.
CONSOLIDATED 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, 2010 and 2009, and the related consolidated statements of income, equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes, examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoResources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), GeoResources, Inc and subsidiaries internal control over financial reporting as of December 31, 2010 based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 11, 2011 expressed an unqualified opinion that GeoResources, Inc and subsidiaries maintained, in all material respects, effective internal control over financial reporting.
/s/ Grant Thornton LLP
March 11, 2011
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these 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.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except share and per share amounts)
The accompanying notes are an integral part of these statements
CONSOLIDATED STATEMENTS OF EQUITY and COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2010, 2009 and 2008
(In thousands, except share data)
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS