ITEM 1. BUSINESS
General
We are an independent oil and gas company operating in the Illinois Basin and the Appalachian Basin. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties. We were incorporated in the state of Delaware on March 8, 2007. We completed our initial public offering and the Reorganization Transactions in July 2007. Our common stock currently trades on the NASDAQ Global Market under the symbol “REXX”. The information set forth in this report is exclusive of our discontinued operations related to the Southwest Region properties, unless otherwise noted, which are classified as Discontinued Operations on our Consolidated and Combined Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets.
At December 31, 2008, our proved reserves had the following characteristics:
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11.0 MMBOE;
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54% crude oil;
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65% proved developed; and
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a reserve life index of approximately 11 years (based upon fourth quarter 2008 production).
At December 31, 2008, we operated approximately 2,314 wells. For the quarter ended December 31, 2008, we produced an average of 2,684 net BOE per day, composed of approximately 82% oil and approximately 18% natural gas.
We are one of the largest oil producers in the Illinois Basin, with an average net daily production of 2,121 barrels of oil per day in 2008. In addition to our developmental shallow oil drilling in the Illinois Basin, we are in the process of implementing an enhanced oil recovery project, or EOR project, in the Lawrence Field in Lawrence County, Illinois, which we refer to as our Lawrence Field ASP Flood Project.
In our Appalachian Basin, we averaged net production of approximately 2.8 MMcf in 2008 of natural gas per day and have been continuing to grow our reserves and production in the region through developmental shallow natural gas drilling and exploratory drilling, including our Marcellus Shale drilling projects. As of December 31, 2008, we controlled approximately 88,000 gross (62,000 net) acres in areas of Pennsylvania that we believe are prospective for the Marcellus Shale exploration.
Our total operating revenues for the year ended December 31, 2008 were $68.0 million. Revenues were derived from $84.0 million in oil and natural gas sales and $123,000 in other revenues, partially offset by $16.2 million in realized losses on derivatives.
For the year ended December 31, 2008, we drilled 64 gross (61.1 net) wells. The wells drilled in 2008 include 60 gross (58.1 net) that were productive and four gross (three net) that are awaiting completion and expected to be productive during the first quarter of 2009.
The following table shows selected data concerning our continuing operations, and displays our production, proved reserves and undeveloped acreage in our two operating regions for the periods indicated:
(1) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net cash flows before income tax of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. PV-10 should not be considered as an alternative to the pro forma standardized measure of discounted future net cash flows as defined under GAAP. At December 31, 2008, our standardized measure was $68.9 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, please read “Selected Financial and Operating Data-Non-GAAP Financial Measures.” Please also read “Risk Factors-Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”
(2) Undeveloped acreage is 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 includes proved reserves.
Our Competitive Strengths
We believe the combination of the following strengths is directly related to our historical successes and the future implementation of our strategy:
Significant Production Growth Opportunities: We have several projects and properties that we believe are capable of significant proved reserves and production growth. These include:
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our Lawrence Field ASP Flood Project in Illinois (please see “Item 2. Properties-Illinois Basin-Lawrence Field ASP Flood Project”);
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our large acreage position in Pennsylvania prospective for Marcellus unconventional shale exploration (please see “Item 2. Properties-Appalachian Basin-Marcellus Shale”); and
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our conventional shallow natural gas drilling opportunities in the Appalachian Basin and our conventional shallow oil drilling opportunities in the Illinois Basin.
Market Leader in the Illinois Basin: We are one of the largest oil producers and a market leader in the Illinois Basin, which enables us to realize a current premium over the basin-posted prices on our oil production and a competitive cost structure due to economies of scale, and provides us with a unique local knowledge of the basin. We believe these advantages may enhance our ability to continue making strategic acquisitions in the basin.
Experienced Management Team with a Proven Track Record: We believe we have significant technical and managerial experience in our core operating areas. Our technical team of geologists and engineers has an average of over 20 years of experience, primarily in the Illinois and Appalachian Basins. This experience and the capabilities of our management team have enabled us to build a high quality asset base of proved reserves and growth projects, both organically and through selective acquisitions.
Financial Flexibility: As of December 31, 2008, we had approximately $7 million of cash on hand. In addition, our senior credit facility had a borrowing capacity of $90 million as of December 31, 2008, of
which $75 million was available for working capital purposes or to fund new acquisitions. Lastly, we believe our oil and gas financial derivative activities enable us to achieve more predictable cash flows and reduce our exposure to short-term fluctuations in oil and natural gas prices while we continue to develop our properties.
For a more detailed discussion of our derivative activities, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Incentivized Management Ownership: We believe our performance is enhanced when our employees and directors think and act like owners. To achieve this, we believe in rewarding and encouraging our employees and directors through equity ownership in our company. As of March 10, 2009, our directors and officers beneficially owned approximately 31% of our outstanding common stock. Therefore, the interests of our directors and executive officers are closely aligned with those of our stockholders.
Business Strategy
Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings. The following are key elements of our strategy:
Employ Technological Expertise: Our strategy is to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 97% over the last three years and has helped us improve operations and enhance field recoveries. We intend to apply this expertise to our proved reserve base and our development projects.
Develop Our Existing Properties: Our focus is to develop our asset base in both of our operating basins, including:
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our Marcellus Shale natural gas play with approximately 88,000 gross (62,000 net) acres;
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our Lawrence Field ASP Flood Project in Illinois; and
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our inventory of approximately 235 proved undeveloped locations and proved developed non-producing wells.
Pursue Strategic Acquisitions and Joint Ventures: We plan to continue to acquire and lease additional oil and natural gas properties in our core areas of operation. We believe that our strong history of acquisitions, leading position in the Illinois Basin and technical expertise situate us well to attract joint venture partners and pursue strategic acquisitions.
Focus on Operations: We intend to focus our future acquisition and leasing activities on properties where we have a significant working interest and can operate the property to control and implement the planned exploration and development activity.
Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations: As we continue to increase our oil and natural gas production and develop our existing properties, we believe that our per unit production costs will benefit from increased production in lower cost operations and through better use of our existing infrastructure over a larger number of wells.
Maintain Flexibility: Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer capital projects to seize an attractive acquisition opportunity or reallocate capital towards projects where we believe we can generate higher than anticipated returns. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower price environments as well as providing more consistent financial results.
Significant Accomplishments in 2008
During 2008, our significant accomplishments included:
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Successful completion of public offering: We completed a public offering of common stock in May 2008.
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Commenced ASP pilot chemical injection: We commenced injection operations in our two alkali-surfactant-polymer (“ASP”) pilot projects in the Lawrence Field.
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Achieved Marcellus Shale leasing goal and drilled initial test wells: We achieved our targeted acreage leasing goals in areas prospective for the Marcellus Shale in certain regions of Pennsylvania and successfully drilled test wells in each of our main project areas.
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Completed divestiture of New Albany Shale acreage: We successfully completed the sale of approximately 79,000 net undeveloped acres in Indiana and certain related non-producing wells in August 2008, the proceeds of which were used to fund a portion of our Marcellus Shale exploration projects and our ASP projects.
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Production Growth: We increased annual production from continuing operations by approximately 5% from 901 MBOE in 2007 to 949 MBOE in 2008.
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Financial Performance: Our revenue increased by 31% in 2008 over the previous year, and our EBITDAX, as defined in “Item 6. Selected Financial Data-Non-GAAP Financial Measures,” grew by 39% over the previous year to $25.3 million.
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Successful Drilling Program: In 2008, we drilled and completed or recompleted 64 gross wells. Our overall success rate was 100%.
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Continued Expansion of Drilling Inventory: To continue to grow, the size of our prospect inventory must remain large. Our drilling inventory currently includes approximately 2,000 potential drilling locations. During 2008, we expanded our acreage position in the Marcellus Shale play by approximately 107%. As of December 31, 2008, we controlled approximately 84,000 gross (62,000 net) acres in this emerging play in Pennsylvania.
Plans for 2009
On November 6, 2008, we established an initial capital budget of approximately $115 million for 2009, a decrease of 16% from 2008 capital expenditures. The 2009 initial capital budget reflected our plans to commence chemical injection in our first operational unit in the Lawrence Field ASP Flood Project, to operate one rig drilling horizontally throughout the year on our Marcellus Shale acreage in Pennsylvania and to continue to drill our developmental projects in the Appalachian Basin and Illinois Basin.
In December 2008, our board of directors approved a revised 2009 capital budget of $49 million. The decrease was a result of the continued unfavorable economic and commodity price environment. The revised 2009 capital budget reflects our desire to maintain a conservative balance sheet while still continuing to make progress on what we believe to be our highest potential projects. This revised capital budget will allow us to drill approximately six to eight horizontal Marcellus Shale wells and begin ASP chemical injection on two 40-acre units in the Lawrence Field ASP project. We anticipate continuing to make further changes to our 2009 capital budget in the future should the commodity price environment remain negative in order to continue to manage our balance sheet.
The following table summarizes our actual 2008 and our revised estimated 2009 capital expenditures ($ in millions). The estimated capital expenditures are dependent on a number of factors, including industry conditions and our drilling success, and are subject to change. We do not attempt to budget for future acquisitions of proved oil and gas properties.
(1) The Southwestern Region operations have been discontinued and the sale is expected to close in March 2009-see note 4-Discontinued Operations/Assets Held for Sale for additional information.
Production, Revenues and Price History
The following table sets forth information regarding oil and gas production and revenues for continuing operations for the last three years ($ in thousands):
(1) Natural gas is converted at the rate of six Mcf to one BOE and oil is converted at a rate of one Bbl to one BOE
Competition
The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. Additionally, it is difficult to attract and retain employees, particularly those with expertise in high demand areas.
Employees
As of December 31, 2008, we had 147 full-time employees (including four employees at our Southwest Region office), 83 of whom were field personnel. No employees are covered by a labor union or other collective bargaining arrangement. We believe that our relations with our employees are good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field services and on-site production operation services.
Marketing and Customers
We market nearly all of our oil and gas production from the properties we operate for both our interest and that of the other working interest owners and royalty owners.
In the Illinois Basin, we store the oil produced at well site tanks and sell our oil to Countrymark Cooperative, LLP, a local refinery, currently at a premium to the basin-posted prices. This premium is provided to us due to our significant size in the basin relative to other local producers. The oil is purchased at our tank facilities from the refiner and trucked to refinery facilities. The revenue we derived from our sales to Countrymark Cooperative, LLP for the year ended December 31, 2008 constituted approximately 88% of our oil and natural gas sales revenue from continuing operations for such period. As such, we are currently significantly dependent on the creditworthiness of Countrymark Cooperative, LLP. Please read “Item 1A
ITEM 1A. RISK FACTORS
In evaluating our company, the factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows.
Risks Related to Our Company
The current financial crises and deteriorating economic conditions may have a material adverse impact on our business and financial condition that we currently cannot predict.
The economic conditions in the United States and throughout the world have been deteriorating. Global financial markets have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while businesses and consumer confidence have declined and there are fears of a prolonged recession. Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect our business and financial condition. For example:
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the demand for oil and natural gas may decline due to deteriorating economic conditions, which could adversely affect our business, financial condition or results of operations;
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our ability to obtain credit or to access the capital markets may be restricted at a time when we would need to raise capital for our business, including for exploration or development of our reserves; and
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our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
A sustained or further decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The current global credit and economic environment has reduced worldwide demand for energy and resulted in significantly lower oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
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the current global economic downturn;
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changes in global supply and demand for oil and natural gas;
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the condition of the U.S. and global economy;
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the actions of certain foreign states;
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the price and quantity of imports of foreign oil and natural gas;
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political conditions, including embargoes, in or affecting other oil producing activities;
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the level of global oil and natural gas exploration and production activity;
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the level of global oil and natural gas inventories;
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production or pricing decisions made by the Organization of Petroleum Exporting Countries (“OPEC”);
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weather conditions;
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availability of limited refining facilities in the Illinois Basin reducing competition and resulting in lower regional oil prices than in other U.S. oil producing regions;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. Lower prices have negatively impacted the value and quantity of our proved and unproved projects. A sustained or further decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Enhanced Oil Recovery, or EOR, techniques that we may use, such as our Alkali-Surfactant-Polymer flooding in the Lawrence Field, involve more risk than traditional waterflooding.
An EOR technique such as alkali-surfactant-polymer (“ASP”) chemical injection involves significant capital investment and an extended period of time, generally a year or longer, from the initial phase of a pilot program until increased production occurs. The results of any successful pilot program may not be indicative of actual results achieved in a broader EOR project in the same field or area. Generally, surfactant polymer, including ASP, injection is regarded as involving more risk than traditional waterflood operations. The potential reserves associated with our ASP project in the Lawrence Field are not considered proved. Our ability to achieve commercial production and recognize proved reserves from our EOR projects is greatly contingent upon many inherent uncertainties associated with EOR technology, including ASP technology, geological uncertainties, chemical and equipment availability, rig availability and many other factors.
We have limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our operations. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the other areas.
We have limited experience in the drilling and completion of Marcellus Shale wells. As of March 10, 2009, we have drilled six vertical wells to the Marcellus Shale. Other operators in the Appalachian Basin have significantly more experience in the drilling of Marcellus Shale wells, including the drilling of horizontal wells. In addition, we have much less information with respect to the ultimate recoverable reserves and production decline rates than we have in our other areas of operation. The wells drilled in the Marcellus Shale are drilled deeper than in our other primary areas, which makes the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale will be more extensive and complicated than fracturing other geological formations in our other areas of operation and requires greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.
If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil
and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
If drilling in the Marcellus Shale areas continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Marcellus Shale area may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.
A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
If we are unable to acquire adequate supplies of water for our Marcellus Shale drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.
We use a substantial amount of water in our Marcellus Shale drilling operations. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.
Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.
As a result of a funding gap in the state budget, the governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5% of the value of the natural gas at wellhead, plus 4.7 cents per 1,000 cubic feet of natural gas severed. If enacted, the proposed severance tax would take effect on October 1, 2009. All of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts such a severance tax, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.
A significant part of the value of our production and reserves is concentrated in the Illinois Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates related to these areas could have a material adverse impact our business.
For the year ended December 31, 2008, 82% of our net daily production came from the Illinois Basin area, and, as of December 31, 2008, approximately 54% of our proved reserves were located in the fields that comprise this area. In addition, for the year ended December 31, 2008, approximately 56% of our net daily production came from the Lawrence Field, and, as of December 31, 2008, approximately 33% of our proved reserves were located on this property. Moreover, we plan to allocate approximately 28% of our 2008 capital expenditures to our Lawrence Field ASP Flood Project. If mechanical problems, weather conditions or other events were to curtail a substantial portion of this production, our cash flow could be adversely affected. If ultimate production associated with these properties is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a downward revision of any estimated reserves in these properties, our business, financial condition and results of operations could be adversely affected.
We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations or the loss of our market with Countrymark Cooperative, LLP, in particular, may adversely affect our financial results.
We derive a significant amount of our revenue from a relatively small number of purchasers. While a portion of our oil in the Illinois Basin is sold through an offload facility, a majority of the oil is sold to one refinery, Countrymark Cooperative, LLP. The revenue we received from sales of our oil to Countrymark Cooperative, LLP for the year ended December 31, 2008, constituted approximately 92% of our total oil and natural gas sales revenue from continuing operations for such period. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.
PennTex Illinois and Rex Operating are defendants in a class action lawsuit concerning complaints of hydrogen sulfide emissions from the Lawrence Field, which could expose us to monetary damages or settlement costs.
PennTex Illinois and Rex Operating are defendants in a class action lawsuit asserting that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating has resulted in contamination of the areas surrounding Bridgeport and Petrolia, Illinois, with hydrogen sulfide, or H2S. The complaint, as amended, asserts several causes of action, including violation of the Illinois Environmental Protection Act, violation of the federal Resource Conservation And Recovery Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area.
The plaintiffs filed an amended motion for class certification on January 22, 2008. PennTex Illinois and Rex Operating filed a joint motion opposing class certification on February 22, 2008, and various supplements were filed by both parties after that date. On December 19, 2008, the district court issued a preliminary ruling on certification, indicating its conclusion that several of the class action prerequisites were met and that it was likely to certify a class to adjudicate two issues relating to the emission of H2S in the putative class area, while reserving all remaining issues for subsequent individual adjudications. The district court denied the plaintiffs’ motion to certify a class in reference to the plaintiffs’ medical monitoring claim. The district court requested that the plaintiffs submit a revised class definition consistent with its order, which was submitted by the plaintiffs on
January 16, 2009. On January 28, 2009, the defendants filed an objection to the plaintiffs’ revised class definition and requested that the district court deny the plaintiffs’ motion for class certification.
On February 26, 2009, the district court issued an order approving the geographic scope of the plaintiffs’ revised class definition. In its order, the district court denied plaintiffs’ request to include all residents and landowners within the geographic area of the class owning property since October 17, 2006, the date the lawsuit was filed, and limited the class to only current property owners. To date, the district court has not set a date for the final pre-trial conference or a trial date. On March 11, 2009, PennTex Illinois and Rex Operating filed a petition for leave to appeal with the United States Court of Appeals for the Seventh Circuit to appeal the class certification order on an interlocutory basis.
We intend to vigorously oppose the certification of the class and the claims that have been asserted by the plaintiffs’ against PennTex Illinois and Rex Operating in this lawsuit. If, however, as a result of this lawsuit, we are required to pay significant monetary damages or settlement costs in excess of any insurance proceeds, our financial position and results of operations could be substantially harmed. (For more information regarding this lawsuit, please see “Item 3. Legal Proceedings.”)
Our results of operations and cash flow may be adversely affected by risks associated with our oil and gas financial derivative activities, and our oil and gas financial derivative activities may limit potential gains.
We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. During the twelve months ended December 31, 2008, we incurred realized losses of $16.2 million from our financial derivatives, which effectively decreased our total revenues from our oil and gas sales. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays), or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our oil and gas financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our senior credit facility with KeyBank National Association, the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.
If oil and natural gas prices continue to decrease or stay at depressed levels, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.
There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas
properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and stockholders’ equity.
Additional write downs could occur if oil and gas prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common stock.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.
We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Our future success will depend on the success of our exploitation, exploration, development and production activities. Our 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. Our 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. Please read “Item 1A. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” below for a discussion of the uncertainties involved in these processes. Our 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. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
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delays imposed by or resulting from compliance with regulatory requirements;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel;
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equipment failures or accidents;
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adverse weather conditions;
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reductions in oil and natural gas prices;
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oil and natural gas property title problems; and
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market limitations for oil and natural gas.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
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actual prices we receive for oil and natural gas;
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actual cost of development and production expenditures;
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the amount and timing of actual production;
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supply of and demand for oil and natural gas; and
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changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.
We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.
We do not operate all of the properties in which we own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:
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nature and timing of drilling and operational activities;
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timing and amount of capital expenditures;
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expertise and financial resources;
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the approval of other participants in drilling wells; and
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selection of suitable technology.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Producing oil and natural gas reservoirs generally is characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.
Our future acquisitions may yield revenue or production that varies significantly from our projections.
In acquiring producing properties, we will assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make 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 capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and public stock offerings. We intend to finance our capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:
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our proved reserves;
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the level of oil and natural gas we are able to produce from existing wells;
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the prices at which oil and natural gas are sold; and
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our ability to acquire, locate and produce new reserves.
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves. Also, our credit facility contains covenants that restrict our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.
We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment and supplies. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, and we may not have enough insurance to cover all of the risks that we face.
We maintain insurance coverage against some, but not all, potential losses to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;
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fires and explosions;
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personal injuries and death; and
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natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our financial condition, results of operations and cash flows.
Our business may suffer if we lose key personnel.
Our operations depend on the continuing efforts of our executive officers and senior management. Our business or prospects could be adversely affected if any of these persons does not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.
We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, and local laws and regulations. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:
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the location and spacing of wells;
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the unitization and pooling of properties;
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the method of drilling and completing wells;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells;
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the disposal of fluids used or other wastes generated in connection with our drilling operations;
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the marketing, transportation and reporting of production; and
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the valuation and payment of royalties.
Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.
Our operations expose us to substantial costs and liabilities with respect to environmental matters.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive relief. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.
We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.
Being a public company has increased our expenses and administrative workload.
We completed our initial public offering in July 2007. As a public company, we must comply with various laws and regulations, including the Sarbanes-Oxley Act of 2002 and related rules of the Securities and Exchange Commission (“SEC”), and requirements of NASDAQ. We were not required to comply with all of these laws and requirements before our initial public offering. Complying with these laws and regulations requires the time and attention of our board of directors and management, and increases our expenses. Among other things, we must:
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maintain and evaluate a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
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maintain policies relating to disclosure controls and procedures;
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prepare and distribute periodic reports in compliance with our obligations under federal securities laws;
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institute a more comprehensive compliance function, including with respect to corporate governance; and
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involve to a greater degree our outside legal counsel and accountants in the above activities.
In addition, being a public company has made it more expensive for us to obtain director and officer liability insurance. In the future, we may be required to accept reduced coverage or incur substantially higher costs to obtain this coverage. These factors could also make it more difficult for us to attract and retain qualified executives and members of our board of directors, particularly directors willing to serve on our audit committee.
Risks Related to Our Common Stock
Our common stock has only been publicly traded since July 30, 2007, and the price of our common stock has fluctuated substantially since then and may fluctuate substantially in the future.
Our common stock has only been publicly traded since our initial public offering on July 30, 2007. The price of our common stock has fluctuated significantly since then. From July 30, 2007 to March 10, 2009, the closing trading price of our common stock ranged from a low of 1.04 per share to a high of $28.78 per share. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:
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changes in oil and natural gas prices;
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variations in quarterly drilling, recompletions, acquisitions and operating results;
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changes in financial estimates by securities analysts;
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changes in market valuations of comparable companies;
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additions or departures of key personnel;
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future sales of our stock; and
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other factors discussed in the “Risk Factors” section and elsewhere in this report.
We may fail to meet the expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result.
You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.
We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We are authorized to issue 100,000,000 shares of common stock and 100,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. We may also issue additional shares of our common stock, or other securities that are convertible into or exercisable for our common stock, in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.
Our certificate of incorporation, bylaws and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and our Chairman and other executive officers, which collectively beneficially own approximately 31% of the outstanding shares of our common stock as of March 10, 2009.
Provisions in our certificate of incorporation and bylaws will have the effect of delaying or preventing a change of control or changes in our management. These provisions include the following:
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The ability of the board to issue shares of our common stock and preferred stock without stockholder approval;
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The ability of our board of directors to make, alter or repeal our bylaws without further stockholder approval;
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The requirement for advance notice for nominations for directors to our board of directors and for proposing matters that can be acted upon by stockholders at stockholder meetings; and
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Stockholders may not take action by written consent.
In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us.
Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 31% of the outstanding shares of our common stock. Although this is not a majority of our outstanding common stock, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring approval by our stockholders, including the election and removal of directors, any proposed merger, consolidation or sale of all or substantially all of our assets and other corporate transactions.
These provisions in our certificate of incorporation and bylaws and under Delaware law, and this concentrated ownership of our common stock by our Chairman and executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.
Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.
We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our senior credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES
The table below summarizes certain data for our core operating areas for the year ended December 31, 2008:
Segment reporting is not applicable to us, as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.
Illinois Basin
In the Illinois Basin, we own an interest in 2,086 wells. We have approximately 60,000 gross (34,000 net) acres under lease. During the third quarter of 2008, we sold approximately 79,000 net undeveloped acres in Indiana and certain non-producing wells, which was a part of our New Albany Shale exploration projects, for approximately $8.4 million in proceeds.
Total proved reserves decreased approximately 6.1 MMBOE, or 51%, to approximately 5.9 MMBOE at December 31, 2008 when compared to year-end 2007, which was primarily a result of the decline in oil prices during the second half of 2008. Annual production increased 1% over 2007. Capital expenditures in 2008 for developmental drilling and facility improvements in the region were approximately $22.3 million, which funded the drilling of 38 gross (37.9 net) development wells, all of which were completed and producing as of December 31, 2008. Capital expenditures in 2008 also funded the recompletion of four gross (four net) recompletions. Capital expenditures for drilling and facilities development for the Lawrence Field ASP Flood Project in Lawrence County, Illinois totaled approximately $23.5 million, which funded facilities and project development for our pilot program and future larger scale ASP plans.
At December 31, 2008, the Illinois Basin had a development inventory of 60 proven drilling locations and 116 proven recompletions. Development projects include recompletions, infill drilling and continued refinement of secondary recovery operations. These activities also include increasing reserves and production through
aggressive cost control, upgrading lifting equipment, improving gathering systems and surface facilities and performing re-stimulations and re-fracturing operations.
Lawrence Field ASP Flood Project
We are implementing an alkali-surfactant-polymer (“ASP”) flood project in the Cypress and Bridgeport Sandstone reservoirs of our Lawrence Field acreage. The Lawrence Field ASP Flood Project is one of our largest projects. The Lawrence Field ASP Flood Project is considered an Enhanced Oil Recovery (“EOR”) project, which refers to recovery of oil that is not producible by primary or secondary recovery methods.
The Lawrence Field in Lawrence County, Illinois, is believed to have produced more than 400 million barrels of oil from 23 separate horizons since its discovery in 1906. We currently own and operate 21.2 square miles (approximately 13,500 net acres) of the Lawrence Field, and our properties account for approximately 85% of the current total gross production from the field. The Cypress (Mississippian) and the Bridgeport (Pennsylvanian) sandstones are the major producing horizons in the field. To date, approximately 40% of the estimated one billion barrels of original oil in place has been produced.
In the 1960s, 1970s and 1980s, a number of EOR projects using surfactant polymer floods were implemented in several fields in the Illinois Basin by Marathon Oil Corp. (“Marathon”), Texaco and Exxon in an attempt to recover a portion of the large percentage of the original oil in place that was being bypassed by the secondary recovery waterflood. These test projects reportedly were able to recover incremental oil reserves of 15% to 30% of the original oil in place.
In 1982, Marathon began a surfactant polymer flood project in the Lawrence Field on the Robins Lease, a 25-acre lease in the Lawrence Field within one mile of the site of one of our pilot test locations. This project was initiated at a time when the price per barrel of oil was below $15 and the technology of combining alkali and surfactant with polymer, which significantly reduces costs of recovery compared with the previous surfactant polymer floods, had not yet been fully developed. Despite the high costs of the surfactant polymer flooding employed by Marathon and the low oil prices, the project produced an estimated 450,000 incremental barrels, or an estimated 21% the of original oil in place. While we believe the results of this project are pertinent, there can be no assurance that our Lawrence Field ASP Flood Project, which uses technology that was not developed at the time of the Robins Lease flood, will achieve similar results.
ASP technology, which uses mechanisms to mobilize bypassed residual oil similar to these previous surfactant polymer floods but at significantly lower costs, has been applied by other companies in several fields around the world resulting in significant incremental recoveries of the original oil in place. Chemicals used in the Lawrence Field ASP Flood Project are an alkali (NaOH or Na2CO3), a surfactant and a polymer. The alkali (1% to 2%) and surfactant (0.1% to 0.4%) combination washes residual oil from the reservoir mainly by reducing interfacial tension between the oil and the water. The polymer (800 to 1400 parts per million) is added to improve sweep displacement efficiency. ASP technology achieves its incremental recovery by reducing capillary forces that trap oil, improving aerial and vertical sweep efficiency and reducing mobility ratio.
Our Lawrence Field ASP Flood Project will use ASP technology to flood our Lawrence Field wells. The goal of our Lawrence Field ASP Flood Project is to duplicate the oil recovery performance of the surfactant polymer floods conducted in the field in the 1980s, but at a significantly lower cost. We expect this cost reduction to be accomplished by utilizing newer technologies to optimize the synergistic performance of the three chemicals used, and by using alkali in the formula, which would allow us to use a significantly lower concentration of the more costly surfactant.
In 2000, PennTex Illinois, then known as Plains Illinois, Inc., and the U.S. Department of Energy conducted a study on the potential of an ASP project in the Lawrence Field, with consulting services provided by an independent engineering firm specializing in the design and implementation of chemical oil recovery systems.
Based on the modeling of the reservoir characteristics and laboratory tests with cores taken in the Lawrence Field, the evaluation found oil recovery in the field could be increased significantly by installing an ASP flood. Similar EOR techniques have been successfully demonstrated in fields around the world to recover an additional 15% to 30% of the original oil in place. However, there can be no assurance that our Lawrence Field ASP Flood Project will achieve similar results.
In 2006, we engaged a third-party consultant to review and update the evaluation on the application of the ASP process to the Lawrence Field. This evaluation, based on laboratory results, recommended two pilot areas to evaluate the ASP process in the Bridgeport and Cypress sandstones. The ASP pilot test locations are positioned in areas that we believe are representative of variabilities that can be expected in these reservoirs. Based on our consultant’s recommendations, we drilled and cored the central producing well in each of the two proposed pilot test areas. These cores were sent to our consultant for ASP chemical system design. During 2007, our consultant completed its linear and radial core flood analysis on the Cypress and Bridgeport sandstones, which in the laboratory resulted in an oil recovery rate as high as 21% of the estimated original oil-in-place in the Cypress sandstone, and 24% of the original oil-in-place in the Bridgeport sandstone. These results were in line with our initial projections.
During the second quarter of 2008, we commenced the ASP chemical injection in our two pilot projects. Both of the pilots demonstrated a response to the chemical injection during the third quarter of 2008, as indicated by an increase in both oil production and the oil cut ratio. Each pilot area had individual wells whose oil cut exceeded 10% after the initial response, whereas the oil cuts for both pilots at the time ASP injection was initiated were less than 1%. Our Lawrence Field ASP Project is not a proved project nor are any of the potential reserves associated with this project considered proved at this time. Our current plans for 2009 include approximately $14 million of capital allocated to developing two 40-acre ASP flood units. These plans may be altered pending analysis of our two pilots’ performance and the oil price environment during the year.
Appalachian Basin
As of December 31, 2008, we own an interest in approximately 584 producing natural gas wells in the Appalachian Basin, predominantly in Pennsylvania. These wells are characterized as shallow, predominantly drilled on 40 acre spacing at depths less than 5,000 feet, natural gas wells which have historically been long-life shallow decline reserves. In addition to our producing wells in the basin, we own 49 proved undeveloped drilling locations with total reserves of 5.9 Bcf, and three locations with proved developed non-producing reserves totaling 189 MMcf. At December 31, 2008, we had approximately 111,000 gross (72,000 net) acres in the Appalachian Basin under lease, of which 74,000 gross (55,000 net) acres were undeveloped.
Reserves at December 31, 2008 increased 3.0 Bcf, or 142%, from 2007 due primarily to drilling additions, including Marcellus Shale exploration, which were partially offset by a decrease in natural gas prices. Annual production increased 32% over 2007. Capital expenditures in 2008 for drilling and facility development in the region were approximately $7.1 million, which funded the drilling of 18 gross (16.2 net) development wells, all of which were completed and producing as of December 31, 2008. During 2008, the region achieved a 100% drilling success rate.
Marcellus Shale
A large portion of our property in Pennsylvania is located in areas where active exploration for the Marcellus Shale, by companies such as Range Resources Corporation (NYSE:RRC), Equitable Resources, Inc. (NYSE:EQT), EOG Resources, Inc. (NYSE:EOG) and Atlas Energy Resources, LLC (NYSE: ATN), is occurring with encouraging results. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on our acreage in southwestern and central Pennsylvania. As of December 31, 2008, we had interests in approximately 88,000 gross (62,000 net) Marcellus Shale prospective acres in these areas of Pennsylvania and we continue to expand our position.
During 2008, we met our goal of drilling at least one well in each of our main project areas. Capital expenditures in 2008 for drilling and facility development totaled $15.2 million, which funded the drilling of eight gross (seven net) exploratory wells, of which four gross (four net) were completed and producing and four gross (three net) were awaiting completion and expected to be productive. Our exploration activity added approximately 15.9 Bcf to our total proved reserves. Our plans for 2009 have allocated approximately $28.8 million in capital expenditures to our Marcellus Shale project areas, which will allow us to drill and complete approximately six to eight net horizontal wells by year end.
Proved Reserves
Netherland, Sewell & Associates, Inc. (“NSAI”) and Schlumberger Consulting and Data Services (“Schlumberger”), independent petroleum engineering firms, evaluated our reserves on a consolidated basis as of December 31, 2008. Schlumberger was contracted to evaluate our proved reserves associated with our Marcellus Shale exploration, while NSAI evaluated the proved reserves of all of our remaining properties. All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A - Risk Factors-Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our consolidated and combined financial statements for the year ended December 31, 2008 in conjunction with the following reserve estimates. During the year, we filed form EIA-23, which is an annual survey of domestic oil and gas reserves, with the Energy Information Administration for the year ending December 31, 2007.
The following table sets forth our estimated proved reserves at the end of each of the past three years:
(1) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The estimated present value of proved reserves does not give effect to indirect expenses such as debt service and future income tax expense, asset retirement obligations or to depletion, depreciation and amortization. The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
(2) Totals of estimated proved reserves, PV-10 Value and Pro Form Standardized Measure exclude values from our Southwest Region properties which are classified as Held for Sale on our balance sheet.
(3) We converted natural gas to barrels of oil equivalent at a ratio of one barrel to six Mcf.
(4) Represents the present value, discounted at 10% per annum (PV-10), of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2008. The estimated future production is priced at December 31, 2008, without escalation, using $41.00 per bbl and $5.71 per MMBtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Item 6. Selected Historical Financial and Operating Data-Non-GAAP Financial Measures.” Please also read “Item 1A. Risk Factors-Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”
(5) Because each of the Predecessor Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure for 2006 does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.
Acreage and Productive Wells Summary
The following table sets forth, for our continuing operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2008:
(1) Undeveloped acreage is 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 includes proved reserves.
(2) Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.
(3) In addition, we own royalty interests in approximately 136 natural gas wells in the Appalachian Basin.
(4) In addition, we own royalty interests in approximately 110 oil wells in the Illinois Basin.
Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed or we have obtained production from the acreage subject to the lease before the end of the primary term; in which event, the lease will remain in effect until the cessation of production.
The following table sets forth, for our continuing operations, the gross and net acres of undeveloped land subject to leases summarized in the preceding table that will expire during the periods indicated:
Drilling Results
The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities are conducted on a contract basis by independent drilling contractors. We own three workover rigs which are used in our Illinois Basin operations. We do not own any drilling equipment.
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:
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customary royalty interests;
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liens incident to operating agreements and for current taxes;
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obligations or duties under applicable laws;
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development obligations under oil and gas leases; and
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net profit interests.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
General
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. Except as described below, we do not believe we are party to any legal proceedings which, if determined adversely to us, individually or in the aggregate, would have a material adverse effect on our financial position, results of operations or cash flows.
PennTex Illinois and Rex Operating-EPA Enforcement Matter
In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against PennTex Illinois and Rex Operating seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H 2 S) gas and other volatile organic compounds (“VOC’s”) in the course of the companies’ oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The companies’ senior management and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.
As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications with the U.S. EPA and U.S. DOJ, PennTex Illinois and Rex Operating executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, PennTex Illinois and Rex Operating agreed to develop and carry out a written response plan designed to further reduce possible emissions of H 2 S and VOC’s from the companies’ oil wells and facilities in the Lawrence Field that are closest to populated areas. The companies agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required them to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. The parties each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment before any final approval.
On April 4, 2007, PennTex Illinois, Rex Operating and the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field. Under the terms of the proposed consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia. A notice regarding the proposed consent decree was published in the Federal Register on April 19, 2007. The published notice of the proposed consent decree solicited public comments on the terms of the consent decree for a 30 day period expiring on May 21, 2007. The United States did not receive any comments on the proposed consent decree during the public comment period. On June 1, 2007, the United States filed a motion for the approval and entry of the proposed consent decree with the United States District Court for the Southern District of Illinois. On June 6, 2007, the court granted the United States’ motion for approval and entry of the proposed consent decree, thereby resolving the enforcement action
according to the terms described in the consent decree. The consent decree does not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.
As of December 31, 2008, we have substantially met all requirements of the consent decree. In a letter dated February 8, 2008, the U.S. EPA, in consultation with the Illinois EPA, approved our proposed plan and schedule for implementing our H2S control measures in the Lawrence Field. Throughout 2008, we implemented the operating and maintenance procedures and completed the installation of all control measures in accordance with the schedule approved by the U.S. EPA.
PennTex Illinois and Rex Operating-H2S Class Action Litigation
PennTex Illinois and Rex Operating are defendants in a class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois. This action was commenced on October 17, 2006, by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint was amended in March 2007 to add a claim for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. PennTex Illinois and Rex Operating have filed a joint answer to the amended complaint denying virtually all of the allegations in the amended complaint and asserting affirmative defenses thereto.
On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. On January 26, 2007, the court issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The original order provided for an August 2007 deadline for the completion of pre-certification discovery and the filing of the last brief on class certification issues; however, in August 2007, and again in October 2007, the scheduling and discovery order was amended to extend these deadlines to January 2008. The parties to the lawsuit exchanged initial pretrial disclosures as required under the applicable rules, and each side served and responded to pre-deposition written discovery. In addition, the defendants deposed each of the named plaintiffs and each of plaintiffs’ expert witnesses offered in support of plaintiffs’ motion for class certification. The plaintiffs did not elect to depose the defendants’ expert witnesses offered in support of their opposition to class certification.
The plaintiffs filed an amended motion for class certification on January 22, 2008. PennTex Illinois and Rex Operating filed a joint motion opposing class certification on February 22, 2008, and various supplements were filed by both parties after that date. On December 19, 2008, the district court issued a preliminary ruling on certification, indicating its conclusion that several of the class action prerequisites were met and that it was likely to certify a class to adjudicate two issues relating to the emission of H2S in the putative class area, while reserving all remaining issues for subsequent individual adjudications. The district court denied the plaintiffs’ motion to certify a class in reference to the plaintiffs’ medical monitoring claim. The district court requested that the plaintiffs submit a revised class definition consistent with its order, which was submitted by the plaintiffs on January 16, 2009. On January 28, 2009, the defendants filed an objection to the plaintiffs’ revised class definition and requested that the district court deny the plaintiffs’ motion for class certification.
On February 26, 2009, the district court issued an order approving the geographic scope of the plaintiffs’ revised class definition. In its order, the district court denied plaintiffs’ request to include all residents and
landowners within the geographic area of the class owning property since October 17, 2006, the date the lawsuit was filed, and limited the class to only current property owners. To date, the district court has not set a date for the final pre-trial conference or a trial date. On March 11, 2009, PennTex Illinois and Rex Operating filed a petition for leave to appeal with the United States Court of Appeals for the Seventh Circuit to appeal the class certification order on an interlocutory basis.
We believe that there is no evidence that any H2S gas emissions from any of our facilities have caused any damage or injury to any person or property, and we intend to vigorously defend against the claims that have been asserted against PennTex Illinois and Rex Operating in this lawsuit. Because this lawsuit is in its initial phase, however, and because it is usually difficult to predict the outcome of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or to estimate the amount or the range of potential loss should the outcome be unfavorable to us.
Pursuant to the terms of a pollution liability policy with Federal Insurance Company, we have insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct our defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with us, Federal Insurance Company has agreed to pay a substantial portion of our costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of our agreement, we are required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
We completed the initial public offering of our common stock on July 30, 2007. Since that time, our common stock has been quoted on NASDAQ under the symbol “REXX”. Before then, there was no public market for our common stock. As of March 10, 2009, there were approximately 64 holders of record of our common stock.
The following table sets forth, for the periods indicated, the range of the daily high and low sale prices for our common stock as reported by NASDAQ.
Dividends
We have not paid cash dividends on our common stock since our inception in July 2007. We do not anticipate paying any dividends on the shares of our common stock in the foreseeable future. We currently intend to reinvest our earnings to finance the expansion of our business. In addition, the terms of our senior credit facility restricts our ability to pay cash dividends to holders of our common stock.
Issuer Purchases of Equity Securities
We do not have a stock repurchase program for our common stock.
Use of Proceeds from Public Offering of Common Stock
On May 5, 2008, we completed a public offering of 9,775,000 shares of our common stock at an offering price of $20.75 per share. These shares included 5,775,000 shares offered by us (which includes 1,275,000 shares sold pursuant to the exercise of an over-allotment option granted to the underwriters of the offering) and 4,000,000 shares sold by certain selling stockholders. The net proceeds to us from the underwritten public offering, after underwriting discounts and offering expenses of approximately $6.7 million, were approximately $113.1 million. The net proceeds have been used to repay borrowings under our senior credit facility and to fund, in part, our capital expenditure program for 2008, including our enhanced oil recovery project in the Lawrence Field in Lawrence County, Illinois and our leasing and drilling activities in the Marcellus Shale, and for other corporate purposes.
Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from July 25, 2007, the date our common stock was first publicly traded, to December 31, 2008, with the cumulative total return of the S&P 500 index and the Dow Jones U.S. Oil and Gas Exploration and Production Index over the same period. The graph assumes that $100 was invested on July 25, 2007 in our common stock at the closing market price at the beginning of this period and in each of the other two indices, and the reinvestment of all dividends, if any. This historic stock price performance is not necessarily indicative of future stock performance.
* The performance graph and the information contained in this section is not “soliciting material,” is being “furnished,” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof, and irrespective of any general incorporation language contained in such filing.
ITEM 6.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
Summary Financial Data
The following table shows selected consolidated and combined financial data of Rex Energy Corporation and the Predecessor Companies for each of the periods indicated. The historical consolidated and combined financial data has been prepared for Rex Energy Corporation for the year ended December 31, 2008. The historical combined financial data has been prepared for the Predecessor Companies for the years ended December 31, 2007, 2006, 2005 and 2004. The historical consolidated and combined financial statements for all years presented are derived from the historical audited financial data of Rex Energy Corporation and the Predecessor Companies. All material intercompany balances and transactions have been eliminated. Because each of the Predecessor Companies was taxed as a partnership for each of the periods indicated for federal and state income tax purposes, the following statements make no provision for income taxes for the years ended December 31, 2006, 2005 and 2004 and the seven month period ended July 31, 2007. Provision for income tax is presented for the five month period ended December 31, 2007. This information should be read in conjunction with Item 7
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial and Operating Data” and the consolidated and combined financial statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates, and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” appearing elsewhere in this report. All financial and operating data presented are the results of continuing operations unless otherwise noted.
Overview of Our Business
We are an independent oil and gas company operating in the Illinois Basin and the Appalachian Basin. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively executing our acquisition strategy.
We are headquartered in State College, Pennsylvania, and have regional offices in Canonsburg (Pittsburgh), Pennsylvania and Bridgeport, Illinois.
Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.
On December 23, 2008, we entered into a definitive purchase and sale agreement for the sale of our Southwest Region assets and expect the sale of these assets to close by the end for the first quarter of 2009 for estimated net proceeds of $17.0 million. We have reclassified these assets and associated liabilities as “held for sale” on our Consolidated Balance Sheets and have reported the results of operations under discontinued operations on our Consolidated and Combined Statements of Operations. Total revenues for these properties for the years ended December 31, 2006, 2007 and 2008 were $5.1 million, $5.7 million and $6.4 million, respectively. Total assets held for sale for the years ended December 31, 2006 and 2007 were $18.9 million and 26.4 million, respectively.
Source of Our Revenues
We generate our revenue primarily from the sale of crude oil to refining companies and natural gas to local distribution and pipeline companies. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following ($ in thousands):
We have identified the impact of generally volatile commodity prices in the last several years as an important trend that we expect to affect our business in the future. If commodity prices increase, we would expect not only an increase in revenue, but also the competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas would likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a declining commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomical to drill. Commodity prices during 2008, based on NYMEX, ranged from a high of $145.29 and $13.58 to a low of $39.91 and $5.29, for oil and natural gas, respectively. Should the challenging price environment continue, it may slow the rate of our expected future growth.
Principal Components of Our Cost Structure
Our operating and other expenses consist of the following:
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Production and Lease Operating Expenses. Day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include workovers, repairs to our oil and gas properties not covered by insurance, and various production taxes that are paid based upon rates set by federal, state, and local taxing authorities.
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Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells or dry holes.
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General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, and legal compliance are included in general and administrative expense. General and administrative expense includes non-cash stock-based compensation expense associated with the adoption of SFAS 123R as part of employee compensation.
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Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our senior credit facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow.
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Depreciation, Depletion, Amortization and Accretion. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.
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Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. Currently, all of our federal taxes are deferred; however, at some point, we believe we will use all of our net operating loss carryforwards and we believe we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX, lease operating expenses per barrel of oil equivalent (“BOE”), growth in our proved reserve base, and general and administrative expenses as a percentage of revenue. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2008, 2007 and 2006.
EBITDAX
“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:
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Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;
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The financial performance of our assets and valuation of the entity, without regard to financing methods, capital structure or historical cost basis;
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Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and
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The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
Production Cost per BOE
Production costs are comprised of those expenses which are directly attributable to our producing oil and gas leases, including state and county production taxes, production related insurance, the cost of materials, maintenance, electricity, chemicals, fuel and the wages of our field personnel. Our production costs per BOE are higher than those of many of our peers primarily because of the nature of our oil properties, many of which are mature waterflood properties. As we continue to develop our non-proved properties, we believe this metric will decrease on a per unit basis. Our production cost per BOE produced in 2008 was $27.94 as compared to $24.82 in 2007 and $21.20 in 2006.
Growth in our Proved Reserve Base
We measure our ability to grow our proved reserves over the amount of our total annual production. As we produce oil and gas attributable to our proved reserves, our proved reserves decrease each year by that amount of production. We attempt to replace these produced proved reserves each year through the addition of new proved reserves through our drilling and other property improvement projects and through acquisitions. Our proved reserves have fluctuated since 2006, from 12.5 MMBOE at year end 2006 to 14.1 MMBOE at year end 2007 to
11.0 MMBOE at year end 2008. Our reserve replacement ratio for year end 2006 was approximately 717% based on an increase in total proved reserves of 4.8 MMBOE, total production for the year of 664 MBOE, purchases of reserves of 5.8 MMBOE, extensions, discoveries and other additions of 197 MBOE, and negative revisions of previous estimates of 569 MBOE. Our reserve replacement ratio for year end 2007 was approximately 174% based on an increase in total proved reserves of 1.6 MMBOE, total production for the year of 901 MBOE, purchases of reserves of 84 MBOE, extensions, discoveries and other additions of 342 MBOE, and revisions of previous estimates of 2.0 MMBOE. Our reserve replacement ratio for year end 2008 was approximately a negative 325% based on an decrease in total proved reserves of 3.1 MMBOE, total production for the year of 949 MBOE, purchases of reserves of 165 MBOE, extensions, discoveries and other additions of 2.9 MMBOE, and revisions of previous estimates of negative 5.2 MMBOE.
Our proved reserve base decreased in 2008 when compared to 2007 predominately due to the decline in oil prices at the end of the year. This primarily impacted our Illinois Basin, which accounts for 82% of our total production, and 100% of our oil production. Conversely, our proved reserve base in the Appalachian Basin increased by approximately 142% despite a decrease in natural gas prices.
General and Administrative Expenses as a Percentage of Oil and Gas Revenue
Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our revenue because these expenses have a direct impact on our profitability. In 2008 our general and administrative expenses as a percentage of revenue increased to 22.3% from 15.0% in 2007 and from 16.2% in 2006.
Results of Continuing Operations
General Overview
Operating revenue increased 30.6% for 2008 over 2007. This increase is primarily due to higher production with higher average sales prices per BOE throughout the year, partially offset by increased realized losses on derivative activity. For 2008, production increased 5.3% to 949,000 BOE from 900,927 BOE in 2007 due to the continued success of our drilling programs. Realized losses on derivative activities increased by 161% to $16.2 million for 2008 from $6.2 million for 2007 due to higher average commodity prices during the year.
Operating expenses increased $111.5 million in 2008, or 227%, as compared to 2007. Operating expenses are primarily composed of production expenses, general and administrative expenses, exploration expenses, impairment of oil and gas properties and depreciation, depletion, amortization and accretion expenses (“DD&A”). These increases were primarily due to non-cash impairment expenses of $71.3 million, an increase in losses on the sale of assets of $6.5 million, non-cash compensation expenses of $3.0 million and an increase in DD&A expenses of approximately $20.1 million. The increased DD&A expenses and impairment expenses are directly attributable to the decline in year-end oil and natural gas prices.
Comparison of the Year Ended December 31, 2008 to the Year Ended December 31, 2007
Oil and gas revenue for the years ended December 31, 2008 and 2007 ($ in thousands except price per BOE) is summarized in the following table:
Average realized price received for oil and gas during 2008 was $71.49 per BOE, an increase of 24.0%, or $13.85 per BOE, from the prior year. The average realized price for oil in 2008 increased 27.6% or $16.34 per barrel, whereas the average realized price for natural gas increased 10.1%, or $0.82 per Mcf, from 2007. Our derivative activities effectively decreased net realized prices by $17.04 per BOE in 2007 and $6.88 per BOE in 2006.
Production volume increased 5.3% from 2007 primarily due to continued success with our oil and gas well drilling activities, particularly in the Appalachian Basin where production increased approximately 31.9%, or 251 MMcf. Our production for 2008 averaged approximately 2,593 BOE per day of which 81.8% was attributable to the Illinois Basin and 18.2% to the Appalachian Basin.
Other operating revenue for 2008 of approximately $123,000 increased $21,000, or 20.6%, from 2007. We generate other operating revenue from various activities such as revenue from the transportation of natural gas.
Production and lease operating expense increased approximately $4.2 million, or 18.6%, in 2008 from 2007. The increase in expense can be partially attributed to a higher cost of conducting business in the oil and natural gas industry, as the cost of durable goods has risen throughout our areas of operation for items such as steel, chemicals and electricity. Also contributing to the increase in expense is the greater number of wells in service in 2008 as compared to 2007.
General and administrative (“G&A”) expense of approximately $15.2 million for 2008 increased approximately $7.4 million, or 94.9%, from 2007. The increase in G&A expense was primarily due to increased costs associated with consulting fees related to compliance with the Sarbanes-Oxley Act of 2002 and additional staffing needs in our corporate headquarters and field offices in relation to our growth. Non-cash compensation expenses increased from 2007 by approximately $2.8 million to $3.0 million in 2008, of which approximately $1.1 million is due to the voluntary cancellation of 100,000 stock option awards by members of our board of directors.
Impairment expense increased to $71.3 million in 2008 from $0 in 2007. We recorded impairment expense in 2008 in accordance with Statement of Financial Accounting Standards (“SFAS”) 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”) and SFAS 142, Goodwill and Other Intangible
Assets (“SFAS 142”). At December 31, 2008, we determined that the carrying value of some of our oil and gas properties was not recoverable and exceeded fair value. The decrease in our assets’ fair value was the result of the decrease in oil and natural gas prices at year end as compared to 2007. Contributing to the increase in impairment expense was the impairment of goodwill of approximately $32.7 million.
Exploration expense of oil and gas properties for 2008 increased approximately $2.0 million from $1.2 million in 2007. This increase is primarily due to geological modeling in our Lawrence Field ASP Project and geophysical evaluation and modeling associated with our Marcellus Shale activities during the year.
Depreciation, depletion, amortization and accretion expense of approximately $37.9 million for 2008 increased approximately $20.1 million, or 113%, from 2007. This increase can be primarily explained by the downward revision in the estimated lives of our proved reserves. We calculate our depletion on a units-of-production basis, which accelerated in relation to our lower proved reserves base.
Interest expense, net of interest income, for 2008 was approximately $1.0 million as compared to $5.6 million for 2007. The decrease of $4.6 million is primarily due to the decrease in the average balance on our long-term debt, lines of credit and other loans and notes payable. We used the proceeds of our public offering in the second quarter of 2008 to pay off our entire line of credit balance in May 2008. As a result, we did not have any amounts drawn on our line of credit until October 2008.
Loss on disposal of assets for 2008 was approximately $6.5 million as compared to a gain of $12,000 for 2007. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold. The loss incurred in 2008 is primarily due to the sale of our New Albany Shale acreage holdings in areas of the Illinois Basin.
Unrealized gain on oil and gas derivatives for 2008 was approximately $43.7 million as compared to a loss of $26.3 million for 2007. This change is attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while unrealized gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.
Other expense increased by $150,000 to approximately $168,000 in 2008. The change is primarily due to the recognition of gains and losses on the sale of scrap inventory.
Net loss before minority interests for 2008 was approximately $58.9 million, as compared to a net loss of approximately $29.1 million for 2007 as a result of the factors discussed above.
Comparison of the Year Ended December 31, 2007 to the Year Ended December 31, 2006
Oil and gas revenue for the years ended December 31, 2007 and 2006 ($ in thousands except price per BOE) is summarized in the following table:
Average realized price received for oil and gas during 2007 was $57.65 per BOE, an increase of 11.4%, or $5.91 per BOE, from the prior year. The average realized price for oil in 2007 increased 11.5% or $7.03 per barrel, whereas the average realized price for natural gas decreased 5.6%, or $0.43 per Mcf, from 2006. Our derivative activities effectively decreased net realized prices by $6.88 per BOE in 2007 and $6.68 per BOE in 2006.
Production volume increased 35.6% for the year ended December 31, 2007, as compared to the same period in 2006, primarily due to acquisitions in the Illinois Basin and continued success with our oil and gas well drilling activities. Our production for the year averaged approximately 2,468 BOE per day, of which 85.5% was attributable to the Illinois Basin and 14.5% to the Appalachian Basin.
Other operating revenue for the year ended December 31, 2007 decreased $22,000 to $102,000 from $124,000 for the same period in 2006. We generate other operating revenue from various activities, such as revenue from the transportation of natural gas and from disposal of salt water from non-related parties through a salt water disposal facility we own and operate for our own oil and gas production activities in the Southwestern Region.
Production and lease operating expense increased approximately $8.3 million, or 58.8%, in 2007 from 2006. This expense typically increases as we add new wells and make certain improvements to existing wells in production. This increase was principally due to acquisitions consummated in the final six months of 2006 within the Illinois basin from Tsar Energy II, L.L.C. and Team Energy, L.L.C. and its affiliates.
General and administrative expense increased $2.2 million from 2006 to 2007. This increase was primarily a result of oil and gas property acquisitions in the Illinois Basin during the final six months of 2006 which resulted in reduced overhead income on wells that we operated for Tsar Energy II, L.L.C. This overhead income had offset general and administrative expenses. In October of 2006, we acquired all of the interests of Tsar Energy II, L.L.C. in these wells; at which time we ceased to recognize the overhead income associated with these wells. Additionally, with the completion of our initial public offering in July 2007, we recognized increases to salary and benefit expenses associated with increased staffing levels.
Exploration expense for the year ended December 31, 2007 was $1.2 million as compared to $0 in 2006. The expense incurred during 2007 can be attributed to dry hole costs associated with our New Albany Shale exploration.
Depreciation, depletion, amortization and accretion expense for the year ended December 31, 2007 increased approximately $8.9 million, or 101%, from $8.9 million for the same period in 2006. This increase was partially due to an increase in production volume resulting from the Tsar Energy II, L.L.C. and Team Energy, L.L.C. acquisitions in the Illinois Basin. The increase is also partially attributed to approximately $2.1 million of increased depletion and amortization expense realized over the five-month period ending December 31, 2007, which resulted from a step-up in book basis of assets caused by the acquisition of minority interests from the Predecessor Companies.
Interest expense, net of interest income, for the year ended December 31, 2007 was approximately $5.6 million as compared to $6.0 million for the same period in 2006. The decrease of $385,000 was primarily due to the decrease in the average balance on our long-term debt, lines of credit, and other loans and notes payable, which were significantly reduced with the proceeds of our initial public offering that closed on July 30, 2007.
Gain on disposal of assets for the year ended December 31, 2007 was approximately $12,000 as compared to $91,000 for the same period in 2006. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold.
Unrealized loss on oil and gas derivatives was approximately $26.3 million for the year ended December 31, 2007 as compared to a gain of $5.0 million for the same period in 2006. This change can be attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while unrealized gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.
Other expense decreased by $114,000 to $18,000 for the year ended December 31, 2007 as compared to $132,000 for the same period in 2006. The change year is primarily due to the recognition of gain on the sale of scrap inventory.
Net income (loss) before minority interests decreased from a gain of $4.9 million in 2006 to a loss of $29.1 million in 2007 as a result of the factors described above.
Capital Resources and Liquidity
Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a group of banks to secure our senior credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on our senior credit facility as needed to supplement our operating cash flow and as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development or exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the senior credit facilities. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.
Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations have been primarily used to fund exploration and development of our oil and gas interests.
Financial Condition and Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
The following table summarizes our sources and uses of funds for the periods noted:
Net cash provided by operating activities increased by approximately $14.9 million in 2008 when compared to 2007, to $32.4 million. In 2008, cash flows increased primarily due to increases in production, which were a result of continued success with our oil and gas well drilling activities and higher realized oil and natural gas prices. These increases in cash were partially offset by increases in operating costs, particularly lease operating expenses and G&A expenses. The increase in lease operating expenses is attributable to the higher cost of durable goods in the oil and natural gas industry. The increase in G&A expenses was primarily due to increased costs associated with consulting fees related to compliance with Sarbanes-Oxley Act of 2002 and additional staffing needs in our corporate headquarters and field offices in relation to our growth.
Net cash used in investing activities increased by approximately $87.7 million in 2008 when compared to 2007, to $127.8 million. In 2008, cash used increased, in part, due to increased development activity of our oil and gas properties. A significant portion of these expenditures was due to conventional development activities in the Illinois Basin, where we drilled 38 wells, conventional development activities in the Appalachian Basin, where we drilled 18 wells, exploratory and development activities in our Marcellus Shale project areas, where we drilled eight wells and our Lawrence Field ASP Flood project, where we commenced operations on our two pilot areas. Also contributing to our increase in cash used were our undeveloped acreage acquisitions in the Appalachian Basin during the year. These expenditures were a part of the plan to expand our acreage holdings in areas that are prospective for Marcellus Shale exploration. Partially offsetting these expenditures was an increase in proceeds from the sale of assets of approximately $8.6 million, which is primarily attributable to the sale of our New Albany Shale assets.
Net cash provided by financing activities increased by approximately $78.3 million in 2008 when compared to 2007, to $101.3 million. In 2008, cash flows provided by financing increased primarily due to net proceeds received from the issuance of common stock and a decrease in the repayment of debt. We issued common stock in May 2008, which resulted in net proceeds to us that exceeded the net proceeds to us from our initial public offering in 2007 by approximately $25.1 million. Additionally, we had lower debt levels in 2008, subsequently decreasing our net payments of long-term debt by approximately $46.4 million when compared to 2007.
Capital Requirements
Our primary needs for cash are for exploration, development and acquisition of oil and gas properties and repayment of principal and interest on outstanding debt. During 2008, $136.6 million of capital was expended on
drilling projects, facilities and related equipment and acquisitions to purchase additional interests in producing properties and unproved acreage. The capital program was funded by net cash flows from operations, proceeds from borrowings and proceeds from our public offering of common stock in May. The 2009 capital budget of $48.6 million is expected to be funded primarily by cash flows from operations and proceeds from borrowings. To the extent capital requirements exceed internal cash flows and proceeds from asset sales, debt or equity may be issued to fund these requirements. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a further drop in oil and gas prices or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, to extend maturities or to repay debt.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in our operating costs, as well as an increase or decrease in revenues. Inflation has had a minimal effect on us.
Critical Accounting Policies and Recently Adopted Accounting Pronouncements
The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability of outstanding accounts receivable, fair values of financial derivative instruments, contingencies and the results of current and future litigation. Oil and natural gas estimates, which are the basis for units-of-production depletion, have numerous inherent uncertainties. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. These prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially affected by changes in future economic conditions such as the market prices received for sales of oil and natural gas, interest rates, and our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.
Natural Gas and Oil Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2007 and 2008, Netherland Sewell and Associates, Inc. (“NSAI”) and Schlumberger Consulting and Data Services (“Schlumberger”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. Schlumberger evaluated the proved reserves of our Marcellus Shale properties while NSAI evaluated the proved reserves on all of our other properties.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firms adhere to the same guidelines when preparing its reserve reports. The accuracy of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Any of the assumptions inherent in these factors could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new DD&A rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Derivative Instruments
We use put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. We also use interest rate swap agreements to manage interest rate risks associated with our variable rate credit facility. We account for these collar and swap contracts using SFAS 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”).
We have established the fair value of all derivative instruments using estimates determined by our counterparties. These values are based upon, among other things, future prices, volatility, time to maturity and credit 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.
SFAS 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) to be recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.
For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil and natural gas production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings.
Oil and Natural Gas Property, Depreciation and Depletion
We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.
Depletion, depreciation and amortization are calculated using the units-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the units-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review our proved reserve estimates and makes changes as needed to depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold cost and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years.
We account for impairment under the provisions of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. At December 31, 2008, we recognized approximately $38.6 million of impairment on certain oil and gas properties in the Illinois Basin and Appalachian Basin. We also recorded $8.7 million of impairment related to our Southwest Region properties, which was recognized as expense in our results from discontinued operations. The impairment of these properties can be attributed to the decline in oil and natural gas prices at December 31, 2008, as compared to 2007.
Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property, and any remaining proceeds are recognized as a gain.
Goodwill and Intangible Assets
In accordance with SFAS 142, Goodwill and Other Intangible Assets (“SFAS 142”), no amortization is recorded for goodwill or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. At December 31, 2008, our intangible assets consisted of $952,000 of sales agreements that are amortized using the straight line method over an estimated useful life of five years. These intangible assets resulted from the Reorganization Transactions (see note 1-Basis of Presentation and Principles of Consolidation). For the years ended December 31, 2008, 2007, and 2006, we recorded amortization expense of $266,000, $111,000 and $0, respectively. Amortization expense was recorded only for those periods following the Reorganization Transactions.
Goodwill and identified intangible assets that have an indefinite useful life are subject to impairment testing, which we conduct annually, or on an interim basis if events or changes in circumstances between annual tests indicate the assets might be impaired. We perform our annual impairment test for goodwill and identified intangible assets that have an indefinite useful life as of December 31 of each year. The impairment test involves a comparison of the fair value of each tangible and intangible asset to its carrying value. If the fair value is less than the carrying value, a further test is required to measure the amount of impairment. At December 31, 2008, we recorded impairment of goodwill of $32.7 million, which represented 100% of the prior carrying value.
Future Abandonment Cost
We account for future abandonment costs using SFAS 143, Asset Retirement Obligations (“SFAS 143”). This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed.
According to SFAS 143, if the fair value of a recorded asset retirement obligation changes, a revision is to be recorded to both the asset retirement obligation and the asset retirement cost. During the fourth quarter of 2008, we recognized an increase of $9.2 million in the estimated present value of the asset retirement obligations. The primary factors underlying the 2008 fair value revisions were an overall increase in abandonment cost estimates, the effect of changes in inflation and discount rates used in the calculations, and changes to the estimated useful life assumptions.
Deferred Taxes
We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.
We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We have recognized an accrued liability of approximately $327,000 at December 31, 2008 for the estimated cost of pending litigation matters.
Accounting Standards Not Yet Adopted
In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements (“SFAS 160”), which provides direction on reporting minority (noncontrolling) interests in the consolidated financial statements. The standards set forth in SFAS 160 include clearly identifying and labeling noncontrolling interests in the consolidated statement of equity, separate from the parent’s equity; clearly identifying consolidated net income of the parent and the noncontrolling interests on the consolidated statement of income; consistently accounting for changes in the parent ownership interest when the parent preserves its controlling interest; using fair value to measure any retained noncontrolling equity investment of a deconsolidated subsidiary and any resulting gain or loss and providing a level of detail in disclosures that clearly identifies and separates the interests of the parent and the interests of the noncontrolling owners. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. We adopted SFAS 160 as of January 1, 2009. Adoption did not have a material effect on our financial position and results of operations.
In December 2007, the FASB issued SFAS 141 (revised 2007), Business Combinations (“SFAS 141R”). SFAS 141R is a revision of SFAS 141, Business Combinations (“SFAS 141”). SFAS 141R amends SFAS 141 by requiring an acquirer to recognize (i) the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date, (ii) a gain attributable to any “negative goodwill” in a bargain purchase, and (iii) an expense related to acquisition costs. SFAS 141R is effective for fiscal years beginning on or after December 15, 2008. We adopted SFAS 141R as of January 1, 2009. Adoption did not have a material effect on our financial position and results of operations. However, future results of operations or financial condition may be materially affected if we have a significant acquisition.
In February 2008, the FASB issued Staff Position FAS 157-2, which delayed the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at lease annually), until fiscal years beginning after November 15, 2008. The exceptions apply to the following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and the initial recognition of the fair value of asset retirement obligations and restructuring costs. The implementation of SFAS 157 for these assets and liabilities effective January 1, 2009 has not had a material effect on our financial position or results of operations.
In March 2008, the FASB issued SFAS 161, Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We adopted SFAS 161 as of January 1, 2009. Adoption did not have a material effect on our financial position and results of operations.
In December 2008, the SEC adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.
New disclosure requirements include permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; enabling companies to additionally disclose their probable and possible reserves to investors (currently, the rules limit disclosure to only proved reserves); allowing previously excluded resources, such as oil sands, to
be classified as oil and gas reserves; requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period-rather than the year-end price-to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. We expect the new guidance to change our disclosures, DD&A calculations and other fair value measurements. We are currently evaluating the impact for our Form 10-K for the year ending December 31, 2009 and related financial statements.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. (See note 2 Summary of Significant Accounting Policies.)
To mitigate some of our commodity price risk we engage periodically in certain other limited derivative activities, including price swaps and costless collars, to establish some price floor protection.
For the twelve month periods ended December 31, 2008 and 2007, the net realized loss on oil and natural gas derivatives was approximately $16.2 million and $6.2 million, respectively. The losses are reported as net realized loss on derivatives in the Consolidated and Combined Statements of Operations.
For the twelve month period ended December 31, 2008, the net unrealized gain on oil and natural gas derivatives was approximately $43.7 million, as compared to a net unrealized loss of approximately $26.3 million on oil and natural gas derivatives for 2007. The net unrealized gains and losses are reported as net Unrealized Gains (Losses) on Derivatives in the Consolidated and Combined Statements of Operations.
While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil and natural gas. We enter into the majority of our derivative transactions with two counterparties and have a netting agreement in place with each of these counterparties. We do not obtain collateral to support the agreements, but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivative arrangements generally do not apply to all of our production, and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.
For a summary of our current oil and natural gas derivative positions at December 31, 2008, refer to note 10 to our consolidated and combined financial statements, Fair Value of Financial Instruments and Derivative Instruments.
Contractual Obligations
In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of December 31, 2008, we do not have any capital leases nor have we entered into any material long-term contracts for equipment. As of December 31, 2008, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2008. In addition to the contractual obligations listed in the table below, our balance sheet at December 31, 2008 reflects accrued interest on our bank debt of $35,495 which is payable in January 2009.
The following summarizes our contractual financial obligations for continuing operations at December 31, 2008 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.
(1) Represents our minimum obligation for a drilling rig contracted to drill 10 wells in the Appalachian Basin.
(2) Derivative obligations represent net open derivative contracts valued as of December 31, 2008.
Interest Rates
At December 31, 2008, we had $15.0 million of debt outstanding. This bears interest at floating rates, which averaged 4.3% at December 31, 2008. The 30-day London Interbank Offered Rate (“LIBOR”) on December 31, 2008 was 0.4%.
Off-Balance Sheet Arrangements
We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to continue at depressed levels for a substantial amount of time or further decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps and collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices
of oil and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.
We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REX ENERGY CORPORATION
Page
Report of Independent Registered Public Accounting Firm-Financial Statements
Consolidated Balance Sheets at December 31, 2008 and 2007
Consolidated and Combined Statements of Operations for the Years Ended December 31, 2008, 2007 and
Consolidated and Combined Statements of Stockholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006
Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and
Notes to the Consolidated and Combined Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of
Rex Energy Corporation
State College, Pennsylvania
We have audited the accompanying Consolidated Balance Sheets of Rex Energy Corporation as of December 31, 2008 and 2007, and the related Consolidated and Combined Statements of Operations, owners’ equity (deficit) and minority interests, and cash flows of Rex Energy Corporation and Predecessor Companies for each of the years in the three-year period ended December 31, 2008. We have also audited Rex Energy Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rex Energy Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rex Energy Corporation as of December 31, 2008 and 2007, and the consolidated and combined results of operations, owners’ equity (deficit) and minority interest, and cash flows of Rex Energy Corporation and Predecessor Companies for each of the years in the three-year period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Rex Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Malin, Bergquist & Company, LLP
Pittsburgh, Pennsylvania
March 11, 2009
REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Per Share Data)
See accompanying summary of accounting policies and notes to the financial statements
REX ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
($ and Shares in Thousands, Except Per Share Data)
(1) Earnings per common share for 2007 represents a loss from continuing operations of $11,304 and a gain from discontinued operations of $664 for the 5-month period ended December 31, 2007.
See accompanying summary of accounting policies and notes to the financial statements
REX ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN OWNERS’ EQUITY (DEFICIT) AND MINORITY INTERESTS
($ in Thousands, Except Per Share Data)
See accompanying summary of accounting policies and notes to the financial statements
REX ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
($ in Thousands)
See accompanying summary of accounting policies and notes to the financial statements
REX ENERGY CORPORATION AND PREDECESSOR COMPANIES
NOTES TO THE CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Rex Energy Corporation (“the Company”) is an independent oil and gas company operating in the Illinois Basin and the Appalachian Basin. We pursue a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.
We refer to certain companies-Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership-collectively as the “Predecessor Companies.” We refer to each of the Predecessor Companies individually as:
Douglas Oil & Gas Limited Partnership
“Douglas Oil & Gas”
Douglas Westmoreland Limited Partnership
“Douglas Westmoreland”
Rex Energy Royalties Limited Partnership
“Rex Royalties”
Midland Exploration Limited Partnership
“Midland”
New Albany-Indiana, LLC
“New Albany”
PennTex Resources Illinois, Inc
“PennTex Illinois”
PennTex Resources, L.P
“PennTex Resources”
Rex Energy Limited Partnership
“Rex I”
Rex Energy II Limited Partnership
“Rex II”
Rex Energy II Alpha Limited Partnership
“Rex II Alpha”
Rex Energy III LLC
“Rex III”
Rex Energy IV, LLC
“Rex IV”
Rex Energy Operating Corp.
“Rex Operating”
Simultaneously with the consummation of our initial public offering of common stock, through a series of mergers and reorganization transactions, which we refer to as the “Reorganization Transactions,” Rex Energy Corporation acquired all of the outstanding equity interests of the Predecessor Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and subsidiaries together with the Predecessor Companies, after giving effect to the Reorganization Transactions.
The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include (1) subsequent to the reorganization as described below, the consolidated accounts of Rex Energy Corporation and (2) prior to the reorganization the Predecessor Companies, the combined accounts of the Predecessor Companies under the common ownership of Lance T. Shaner. The consolidated and combined financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have a significant influence, but not control, are accounted for using the equity method of accounting, are carried at our share of net assets and are included in other assets on the balance sheet. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenue on our Consolidated Statement of Operations. All material intercompany balances and transactions have been eliminated.
The combined financial statements of the Predecessor Companies reflect the assets, liabilities, revenues, expenses and cash flows on a gross basis, and the economic interests not owned by Lance T. Shaner are reflected as minority interests. All of the Predecessor Companies were under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Energy Operating Corp.
On July 30, 2007, we reorganized by acquiring all of the outstanding equity interests of each of the Predecessor Companies through a series of mergers and Reorganization Transactions. The Reorganization Transactions occurred simultaneously with the consummation of our initial public offering of common stock. The Reorganization Transactions were accounted for partially as an exchange of entities under common control for the interests in the Predecessor Companies which were contributed by Lance T. Shaner, and partially as an acquisition of minority interests using the purchase method of accounting for all the predecessor owners other than Lance T. Shaner pursuant to Statement of Financial Accounting Standards (“SFAS”) 141, Business Combinations (“SFAS 141”).
The initial public offering of shares of common stock consisted of 8,800,000 shares of common stock offered and sold by us at an offering price of $11.00 per share. We received gross proceeds from the offering of $96.8 million and incurred approximately $9.0 million in underwriting discounts, commissions, and offering costs associated with the offering.
The Reorganization Transactions resulted in our recognition of the acquisition of minority ownership interests and an associated increase in the book basis of certain property assets. These assets are subject to depletion and amortization expenses. The reorganization also resulted in our becoming subject to federal and state income taxes. Tax expenses had previously passed through to the equity owners of the Predecessor Companies and were not recorded on the books of the Predecessor Companies.
On May 5, 2008, we completed a public offering of 9,775,000 shares of common stock at an offering price of $20.75 per share. These shares included 5,775,000 million shares offered by us (which includes 1,275,000 shares sold pursuant to the exercise of an overallotment option granted to the underwriters’ of the offering) and 4,000,000 shares sold by certain selling stockholders. The net proceeds of the underwritten public offering, after underwriting discounts and offering expenses of approximately $6.8 million, were approximately $113.0 million.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates made in preparing these consolidated and combined financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.
Cash and Cash Equivalents
We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.
Accounts Receivable
Our trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and recorded bad debts as necessary.
We use the allowance method to account for uncollectible accounts receivable. A reserve is recorded for amounts we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. The reserve of $173,000 at January 1, 2007 increased by $12,000 due to bad debt expense and there were no write offs during calendar year 2007. The reserve of $185,000 at January 1, 2008 increased by $115,000 of bad debt expense and there were $163,000 of write offs during calendar year 2008. Accordingly, the allowance for uncollectible receivables was $137,000 at December 31, 2008A summary of our reserve for uncollectible accounts receivable is provided in the table below ($ in thousands):
To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying financial statements.
At December 31, 2008, we carried approximately $4.2 million in production receivable, of which approximately $2.5 million were production receivables due from a single customer, Countrymark Cooperative LLP. At December 31, 2007, we carried approximately $8.1 million in production receivable, of which approximately $5.4 million were production receivables due from a single customer, Countrymark Cooperative LLP.
Inventory
Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil held in terminal tanks located in the field. Oil inventory is accounted for using the average cost method, with average cost defined as production and lease operating expenses net of depreciation, depletion and amortization. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
Oil and Natural Gas Property, Depreciation and Depletion
We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by- property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved
commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.
Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved oil and gas reserves at the lease, unit or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 30 years.
We account for impairment under the provisions of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost; the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. At December 31, 2008 we recognized approximately $47.4 million of impairment on some of our oil and gas properties, which is recorded as Impairment Expense on our Consolidated Statement of Operations. Of this amount, $8.7 million was related to our Southwest Region properties, which are classified as discontinued operations. The impairment of these properties can be attributed to the decline in oil and natural gas prices at December 31, 2008, as compared to 2007.
Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas and Oil Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the year ended December 31, 2006, our independent engineering firm, Netherland, Sewell & Associates, Inc., prepared a reserve and economic evaluation of each of the Predecessor Companies’ proved oil and gas reserves which has been combined by us to
determine our total proved oil and gas reserves for the period. For the years ended December 31, 2008 and 2007, Netherland, Sewell & Associates, Inc. prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves, excluding our Marcellus Shale properties. Schlumberger Consulting and Data Services prepared a consolidated reserve and economic evaluation of our proved gas reserves in our Marcellus Shale regions for the year ended December 31, 2008.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firms adhere to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Any of the assumptions inherent in these factors could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered. The independent reserve engineers estimate reserves annually on December 31. This annual estimate results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Goodwill and Intangible Assets
In accordance with SFAS 142, Goodwill and Other Intangible Assets (“SFAS 142”), no amortization is recorded for goodwill or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. At December 31, 2008, our intangible assets include $952,000 of intangible assets comprised of sales agreements that are amortized using the straight line method over an estimated useful life of five years. These intangible assets resulted from the Reorganization Transactions (see Note 1). For the years ended December 31, 2008, 2007, and 2006, we recorded amortization expense of $266,000, $111,000 and $0 respectively. Amortization expense related to our intangible assets is expected to be $266,000 for 2009, 2010 and 2011 and $155,000 in 2012. The assets will be fully amortized in 2012. Amortization expense was recorded only for those periods following the Reorganization Transactions.
Goodwill and identified intangible assets that have an indefinite useful life are subject to impairment testing, which we conduct annually or on an interim basis if events or changes in circumstances between annual tests indicate the assets might be impaired. We perform our annual impairment test for goodwill and identified intangible assets that have an indefinite useful life as of December 31 of each year. The impairment test involves a comparison of the fair value of each tangible and intangible asset to its carrying value. If the fair value is less than the carrying value, a further test is required to measure the amount of impairment. At December 31, 2008, we recorded impairment of goodwill of $32.7 million, which represented 100% of the prior carrying value and is recorded as Impairment Expense on our Consolidated Statement of Operations.
Future Abandonment Cost
We account for future abandonment costs using SFAS 143, Asset Retirement Obligations (“SFAS 143”). This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed.
According to SFAS 143, if the estimate of fair value of a recorded asset retirement obligation changes, a revision is to be recorded to both the asset retirement obligation and the asset retirement cost. During the fourth
quarter 2008, we recognized an increase of $9.2 million in the estimated present value of the asset retirement obligations. The primary factors underlying the 2008 fair value revisions were an overall increase in abandonment cost estimates, the effect of changes in inflation and discount rates used in the calculations and changes to the estimated useful life assumptions.
Accumulated Other Comprehensive Income (Loss)
We follow the provisions of SFAS 130, Reporting Comprehensive Income (“SFAS 130”), which establishes standards for reporting comprehensive income. Comprehensive income includes net income as well as all changes in equity during the period, except those resulting from investments and distributions to owners. Comprehensive loss from continuing operations was $41.0 million and $15.7 million for the years ended December 31, 2008 and 2007. Comprehensive gain from continuing operations was $2.8 million for the year ended December 31, 2006.
Revenue Recognition
Oil and natural gas revenue is recognized when the oil or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at its applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. We do not currently participate in any gas-balancing arrangements. We do not recognize revenue for oil production held in stock tanks before delivery to the purchaser.
To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying financial statements.
Derivative Instruments
We use put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. We also utilize interest-rate swap agreements to manage interest-rate risks
associated with our variable-rate credit facility. We account for these collar and swap contracts using Statement of Financial Accounting Standards 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). We elect not to use hedge accounting for commodity derivative contracts and interest-rate swaps, and unrealized gains or losses are shown in Other Income and Expense on our Consolidated and Combined Statements of Operations. Realized gains and losses are shown in Operating Revenue on the Consolidated and Combined Statement of Operations.
We have established the fair value of all derivative instruments using estimates determined by our counterparties. These values are based upon, among other things, future prices, volatility, time to maturity and credit 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.
SFAS 133 establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.
For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil and natural gas production activity, our evaluations are not documented, and as a result, we record changes in the derivative valuations in earnings.
Income Taxes
We account for income taxes in accordance with SFAS 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. SFAS 109 requires that the net deferred tax asset be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.
This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Additionally, we establish reserves for uncertain tax positions based upon our judgment regarding potential future challenges to those positions. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.
The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material.
We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net
operating losses and deductible temporary differences. For the year ended December 31, 2008, management has determined, based on positive and negative evidence examined and anticipated future taxable income, that it is now more likely than not that these deferred tax assets will be realized in the future. Accordingly, we determined that it is appropriate to present our deferred tax assets without a valuation allowance.
We adopted Financial Accounting Standards Board (“FASB”) Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), on August 1, 2007. The accounting estimates related to the liability for uncertain tax positions require us to make judgments regarding the sustainability of each uncertain tax position based on its technical merits. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our consolidated financial statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (see note 11-Income Taxes).
Advertising Expense
Advertising costs are expensed as incurred and were approximately $81,000, $27,000 and $39,000 for the years ended December 31, 2008, 2007, and 2006, respectively.
Loan Costs
Loan costs consisted of gross debt issuance costs of approximately $770,000, $690,000 and $1,752,000 for the years ended December 31, 2008, 2007 and 2006, which are presented net of accumulated amortization of $215,000, $42,000 and $608,000, respectively. Loan costs at December 31, 2008 are included in Intangible and Other Assets on the Consolidated Balance Sheets and are amortized over five years.
Stock-based Compensation
Since August 1, 2007, we account for stock-based compensation under the provisions of SFAS 123(R), Share-Based Payment (“SFAS 123R”), which requires us to recognize in the financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options under SFAS 123R.
SFAS 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards(see note 14-Employee Benefit Plans and Equity Plans for additional information).
Earnings Per Share
Earnings per common share are computed by dividing consolidated net income by the weighted average number of common shares outstanding. Diluted earnings per common share are computed by dividing consolidated net income by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. Earnings per share are reflected prospectively from August 1, 2007, the date the Predecessor Companies were acquired by Rex Energy Corporation. Therefore, at December 31, 2007, we had consolidated operations for only five months in the fiscal year period for which earnings per share are relevant. At December 31, 2008, we had 36,569,712 common shares outstanding, 993,700 options outstanding and 73,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities.
Before the Reorganization Transactions, our business was conducted through a group of entities for which there was no single holding entity. Each entity was separately owned by its then existing owners. As a result, there was no single capital structure upon which to calculate historical earnings per share information. Accordingly, earnings per share information has not been presented for historical periods before the Reorganization Transactions.
Recently Issued Accounting Pronouncements
In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements (“SFAS 160”), which provides direction on reporting minority (noncontrolling) interests in the consolidated financial statements. The standards set forth in SFAS 160 include clearly identifying and labeling noncontrolling interests in the consolidated statement of equity, separate from the parent’s equity; clearly identifying consolidated net income of the parent and the noncontrolling interests on the consolidated statement of income; consistently accounting for changes in the parent ownership interest when the parent preserves its controlling interest; measuring any retained noncontrolling equity investment of a deconsolidated subsidiary and any resulting gain or loss using fair value and ensuring that all disclosures provide a level of detail that clearly identifies and separates the interests of the parent and the interest of the noncontrolling owners. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. We adopted SFAS 160 as of January 1, 2009. Adoption did not have a material effect on our financial position and results of operations.
In December 2007, the FASB issued SFAS 141 (revised 2007), Business Combinations (“SFAS 141R”). SFAS 141R is a revision of SFAS 141, Business Combinations (“SFAS 141”). SFAS 141R amends SFAS 141 by requiring an acquirer to recognize (i) the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date, (ii) a gain attributable to any “negative goodwill” in a bargain purchase, and (iii) an expense related to acquisition costs. SFAS 141R is effective for fiscal years beginning on or after December 15, 2008. We adopted SFAS 141R as of January 1, 2009. Adoption had no material effect on our financial position and results of operations. However, future results of operations or financial condition may be materially affected if we have a significant acquisition.
In March 2008, the FASB issued SFAS 161, Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We adopted SFAS 161 as of January 1, 2009. This statement provides only for enhanced disclosures and had no material impact on our financial position or results of operations.
In December 2008, the Securities and Exchange Commission (“SEC”) adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.
New disclosure requirements include permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; enabling companies to additionally disclose their probable and possible reserves to investors (currently, the rules limit disclosure to only proved reserves); allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves; requiring companies to report on the independence and qualifications of a
preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period-rather than the year-end price-to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. We expect the new guidance to change our disclosures, DD&A calculations and other fair value measurements. We are currently evaluating the impact for our Form 10-K for the year ended December 31, 2009 and related financial statements.
Recently Adopted Accounting Pronouncements
We adopted SFAS 157, Fair Value Measurement (“SFAS 157”), effective January 1, 2008. SFAS 157, which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure about fair value measurements. The fair value hierarchy established by SFAS 157 prioritizes the inputs used to measure fair value by giving highest priority (“Level 1”) to unadjusted quoted prices in active markets for identical assets and liabilities and gives the lowest priority (“Level 3”) to unobservable inputs. The adoption of SFAS 157 did not have a significant impact on our consolidated financial statements.
In February 2008, the FASB issued Staff Position FAS 157-2, which delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at lease annually), until fiscal years beginning after November 15, 2008. The exceptions apply to the following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and the initial recognition of the fair value of asset retirement obligations and restructuring costs. The implementation of SFAS 157 for these assets and liabilities, effective January 1, 2009, has not had a material effect on our financial position or results of operations.
Effective January 1, 2008, we also adopted SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement 115 (“SFAS 159”). SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. Under SFAS 159, a business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The adoption of SFAS 159 did not have a material impact on our consolidated financial statements.
We adopted the FASB Staff Position on FASB Interpretation 39-1, Amendment of FASB Interpretation 39 (“FSP FIN 39-1”), effective January 1, 2008. FSP FIN 39-1 permits a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable), against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. The adoption of FSP FIN 39-1 did not have a material impact on our consolidated financial statements.
As of January 1, 2008, we adopted Staff Accounting Bulletin 110 (“SAB 110”), which allows registrants to continue to use the “simplified method” defined in SAB 107 for determining the expected term of “plain vanilla” options. Under SFAS 123R, expected term is one of the primary factors used to measure fair value and compensation expense of share option grants. In SAB 107, the staff stated that it would not expect registrants to use the simplified method for share option grants after December 31, 2007. SAB 110 removes the end date for use of the simplified method but establishes conditions for its use. The adoption of SAB 110 did not have a material impact on our consolidated financial statements.
In May 2008, the FASB issued SFAS 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 sets forth identification of sources for accounting principles and the structure for decision making when selecting the principles to be employed during the preparation of financial statements, for entities in non-governmental industries, that are presented in alignment with United States GAAP. We adopted SFAS 162 effective July 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows.
In October 2008, the FASB issued FASB Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (“FSP FAS 157-3”), which clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was issued and adopted on October 10, 2008 and did not have a material impact on our consolidated financial statements.
3. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS
Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our Consolidated and Combined Statements of Operations from the closing date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions are funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.
2008 Acquisitions and Leasing Activities
On May 8, 2008, our wholly owned subsidiary, R.E. Gas Development, LLC, acquired a 100% working interest in a lease covering 5,761 net undeveloped acres in Centre County in the State of Pennsylvania. The interest was purchased from Resource Recovery, LLC for approximately $17.4 million. Pursuant to the leasing agreement, $5.8 million of this amount was paid in May and $5.8 million was paid in June. The remaining $5.8 million to be paid will be distributed in equal installments of approximately $1.4 million in each of the next four years with the last payment being made in 2012 (see note 7-Commitments and Contingencies).
On June 11, 2008, R.E. Gas Development, LLC, acquired a 100% working interest in leases covering 762 net undeveloped acres in Clearfield County in the State of Pennsylvania. The interests were purchased from individual landowners for approximately $2.2 million. Pursuant to the leasing agreement, $1.1 million of this amount was paid in June. The remaining $1.1 million payment has been deferred and will be distributed in equal installments of approximately $267,000 in each of the next four years with the last payment being made in 2012 (see note 7-Commitments and Contingencies).
On June 13, 2008, R.E. Gas Development, LLC, acquired a 100% working interest in a lease covering 5,722 net undeveloped acres in Clearfield County in the State of Pennsylvania. The interest was purchased from E.M. Brown, Inc. for approximately $17.2 million. Pursuant to the leasing agreement, $15.2 million of this amount was paid in June. The remaining $2.0 million payment has been deferred and will be paid in 2012 (see Note 7, Commitments and Contingencies).
On December 16, 2008, R.E. Gas Development, LLC acquired a 100% working interest in a lease covering 470 net undeveloped acres in Clearfield County in the State of Pennsylvania. The interest was purchased from an individual landowner for approximately $1.2 million.
Throughout the year ended December 31, 2008, our wholly owned subsidiaries, R.E. Gas Development, LLC and Rex I, LLC, acquired 100% working interests in several leases totaling 2,253 net acres in Westmoreland and Clearfield Counties in the State of Pennsylvania. These interests were purchased from various individual landowners for a total of $2.7 million.
2008 Dispositions
During the third quarter of 2008, we sold approximately 79,000 net undeveloped acres in Indiana and certain related non-producing wells, which was a part of our New Albany Shale exploration projects, for approximately $8.4 million in proceeds. A related loss of approximately $6.3 million was recorded as a part of continuing operations on our Consolidated and Combined Statement of Operations.
Also see note 4-Discontinued Operations/Assets Held for Sale, for a discussion of our discontinued operations.
Acquisition of Minority Interests (2007)
Pursuant to the Reorganization Transactions, Rex Energy Corporation acquired interests in the Predecessor Companies from the predecessor owners. These interests were acquired through an exchange of common stock in Rex Energy Corporation.
These transactions have been accounted for partially as a transfer of interests under common control and partially as an acquisition of non-controlling interests in accordance with SFAS 141. The controlling interests of the Predecessor Companies were held by Lance T. Shaner. Those interests are reflected in the consolidated financial statements at the historical cost of the interests contributed. The non-controlling owners’ interests are accounted for using the purchase method of accounting under SFAS 141 and reflected as minority interests in the consolidated financial statements at the fair value of the interests contributed, since such holders did not control the Predecessor Companies before the Reorganization Transactions.
The total consideration paid for the minority interests was $92.8 million and reflects 8,437,521 shares of Rex Energy Corporation common stock, the fair value of which was based upon the initial public offering price of $11.00 per share of common stock. Accordingly, we have reflected the acquired tangible assets at the fair value of the consideration paid. The excess of the purchase price and deferred tax liabilities over the fair value of the tangible assets acquired approximates $34 million as of December 31, 2007, and is included in Intangible and Other Assets-Net and Goodwill in the accompanying financial statements.
The finite-lived intangible assets related to the contractual right to future sales revenue from sales agreements was $1.3 million. The residual amount representing the purchase price in excess of tangible and intangible assets is $32.7 million which represents a net deferred tax liability, and was recorded as Goodwill. At December 31, 2008, we conducted annual impairment testing on our Goodwill and identifiable intangible assets. Our testing determined that Goodwill was impaired and we subsequently wrote down 100% of the book value to $0, which was recorded as impairment expense in our results from continuing operations.
We have determined the following fair values for the acquired assets and liabilities assumed as of the date of acquisition ($ in thousands):
The estimated useful lives of the finite-lived intangibles are expected to be five years. We amortize these finite-lived intangibles over their estimated useful lives using the straight line method.
2007 Acquisitions and Leasing Activities
On February 26, 2007, Rex II acquired a 90.0% working interest in six oil and gas leases covering properties located in Hardin County, Texas for $1,080,000, after which time the operations have been included with those of the Company. The acquisition included interests in three producing oil wells and related infrastructure and equipment. The interests were purchased from the Creditor’s Trust for Central Utilities Production Corp., a creditor’s trust established in connection with a bankruptcy case styled In re Central Utilities Production Corp., Case No. 03-44067, filed in the United States Bankruptcy Court, Eastern District of Texas, Sherman Division. The effective date of the acquisition was February 1, 2007.
On April 17, 2007, Rex II acquired a 52.375%, and an 83.707% working interest in two oil and gas leases covering properties located in Concho County, Texas for $890,000, after which time the operations have been included with those of the Company. The acquisition included interests in 10 producing oil wells, eight water injection wells, three water supply wells, eight shut-in wells and related infrastructure and equipment. The interests were purchased from various working interest owners, including the operator of the properties, Ultra Oil & Gas Inc. Ultra Oil & Gas Inc. acted as agent for the various sellers. The effective date of the acquisition was January 1, 2007.
On May 24, 2007, Rex II acquired a 40.0% working interest in certain undeveloped oil and gas leases covering approximately 18,000 gross acres located in Knox, Daviess, Sullivan and Greene Counties in the State of Indiana. The interests were acquired from HAREXCO, Inc., an Illinois corporation doing business in the State of Indiana under the assumed name of Harris Energy Company (“Harris Energy”), for a purchase price of $1,079,000. In connection with this sale, Harris Energy reserved a 4.0% of 40.0% overriding royalty interest in the conveyed properties and a 10.0% of 40.0% back-in-after-payout working interest in the first five net wells drilled on the acquired properties or any other properties which are subsequently acquired by Rex II from Harris Energy. In connection with the closing, Rex II and Harris Energy entered into an exploration agreement, wherein the parties created an area of mutual interest in certain areas of the above counties, and a joint operating agreement, wherein Rex II was appointed the operator of the covered properties. Rex II also agreed to purchase from Harris Energy a 40.0% working interest in certain oil and gas leasehold interests covering up to 5,878 net acres located in Knox County, Indiana. Pursuant to the agreement between the parties, Rex II was obligated to purchase an interest in only those oil and gas leases which were acquired by Harris Energy on or before August 22, 2007. The purchase price for the interest in these leases is equal to 40.0% of the product of $100.00 and the number of net leasehold acres assigned to Rex II on the closing date. In the event that Rex II purchases an interest in any of these leases, Harris Energy will also be entitled to reserve and retain the same overriding royalty interest and the back-in-after-payout working interest described above.
On September 7, 2007, our wholly owned subsidiary, Rex Energy I, LLC, acquired a 30% working interest in certain undeveloped oil and gas leases covering approximately 70,322 gross acres located in Lawrence, Orange, Washington and Jackson Counties in the State of Indiana for a purchase price of $1,055,000. The interests were acquired from Aurora Oil & Gas Corporation pursuant to an option granted to New Albany on January 27, 2006, the predecessor in interest of Rex Energy I, LLC. In connection with this sale, Aurora reserved a 0.5% overriding royalty interest in the conveyed properties.
On November 29, 2007, R.E. Gas Development, LLC, acquired a 50% working interest in multiple leases covering approximately 16,460 gross and 8,230 net undeveloped acres in Butler and Beaver Counties in the State of Pennsylvania. The interests were purchased from Vista Resources, Inc., a Pittsburgh, Pennsylvania private oil and gas company, for $1,070,000.
2007 Dispositions
There were no significant dispositions for the year ended December 31, 2007.
2006 Acquisitions and Leasing Activities
On January 24, 2006, Rex II and Rex II Alpha acquired a combined 99.5% working interest from Westar Energy, Inc. in 12 oil and gas leases covering properties located in Glassrock, Midland, Reagan and Upton Counties, Texas, for $5,175,000, after which time the operations have been included with those of the Company. The acquisition included interests in 21 producing oil wells and related infrastructure and equipment. The effective date of the acquisition was January 1, 2006.
On February 7, 2006, Rex II and Rex II Alpha acquired a combined average 49.75% working interests from Wadi Petroleum, Inc. in 62 oil and gas leases covering properties located in Terrell County, Texas, for $3,825,000, after which time the operations have been included with those of the Company. The acquisition included interests in 15 producing gas wells, and related infrastructure and equipment, including interests in a gas gathering system. The effective date of the acquisition was December 1, 2005.
On February 1, 2006, New Albany completed an acquisition of certain oil and gas leases and other associated rights from Aurora Energy Ltd. pursuant to a Purchase and Sale Agreement with Aurora dated November 15, 2005. Under this purchase agreement, New Albany purchased from Aurora an undivided 48.75% working interest (40.7% net revenue interest) in (i) leases covering approximately 58,200 acres in several counties in Indiana (the “Leases”) and (ii) all of Aurora’s rights under a Farmout and Participation Agreement with a third party. In addition, Aurora granted an option, exercisable by New Albany until August 1, 2007, to acquire at a fixed price per acre a fifty percent (50.0%) working interest in acreage leased or acquired by Aurora or its affiliates in certain other counties located in Indiana. The total purchase price for the acquisition of the working interests in the Leases and Aurora’s rights under the Farmout Agreement, together with Aurora’s grant of the Option, was $10,500,000. New Albany subsequently acquired, through several transactions, an additional 48.75% working interest in 63,648 gross acres as of December 31, 2006 for $1,473,000.
On March 3, 2006, New Albany completed an acquisition of certain oil and gas leases and other associated rights from Source Rock Resources, Inc. (“Source Rock”) pursuant to a Purchase and Sale Agreement with Source Rock. Pursuant to this purchase agreement, New Albany purchased from Source Rock an undivided 45.0% working interest in leases covering approximately 21,070 gross acres for $736,000. In addition, New Albany subsequently acquired through several transactions an additional 45.0% working interest in leases covering approximately 17,646 gross acres for $332,000 as of December 31, 2006.
In June 2006, Rex II acquired a 29.4% working interest from four individuals, which is referred to as the “Scaggs Acquisition,” for $1,217,000.
On June 28, 2006, Rex III acquired average working interests of 72.0% in approximately 220 producing oil wells and related infrastructure and equipment located in Posey and Gibson Counties, Indiana, and Lawrence County, Illinois from Team Energy, L.L.C., an Illinois limited liability company (“Team Energy”) and certain other companies affiliated with Team Energy, after which time the operations have been included with those of the Company. The effective date of the acquisition was June 1, 2006. The total acquisition price was $22,702,000.
On October 3, 2006, Rex IV acquired average working interests of 49.0% in certain oil producing properties and related wells and equipment located in the Lawrence, West Kenner, and St. James fields in Illinois, and the El Nora field in Indiana (the “Illinois and Indiana Properties”) for $35,172,000 from Tsar Energy II, L.L.C. (“Tsar”), after which time the operations have been included with those of the Company. The effective date of the acquisition was October 1, 2006. PennTex Resources and PennTex Illinois, companies affiliated with Rex IV, own average working interests of 25.0% and 26.0%, respectively, in the Illinois and Indiana Properties. PennTex Illinois is the operator of the Illinois and Indiana Properties. The acquisition of the working interest of Tsar in the Illinois and Indiana Properties by Rex IV was accounted for as a purchase.
2006 Dispositions
There were no significant dispositions for the year ended December 31, 2006.
4. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE
On September 3, 2008, our board of directors authorized management to pursue the sale of our Southwest Region assets. In accordance with SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”), we have reclassified these assets and associated liabilities as “held for sale” on our balance sheet and have reported the results of these operations under discontinued operations on our Consolidated Statement of Operations. The recording of DD&A expense related to our Southwest Region assets ceased on September 3, 2008.
We evaluated the value, less cost to sell, of our Southwest Region assets, as of December 31, 2008, and determined that the carrying amount of the assets exceeded their fair value. We subsequently recorded an impairment expense of approximately $8.7 million to adjust the carrying amount of the assets to fair value, less costs to sell. We have included $18.9 million and $26.4 million of assets classified as held for sale in the accompanying balance sheets as of December 31, 2008 and December 31, 2007, respectively, which represents the fair value of the oil and gas properties of our Southwest Region assets. We have included $1.8 million and $1.2 million, respectively, of liabilities associated with the assets held for sale, which represents the future abandonment cost of those oil and gas properties in addition to miscellaneous liabilities that will transfer to the purchaser. Additionally, we have reclassified the results of discontinued operations in our Consolidated Statement of Operations as a loss of $7.7 million, a loss of $0.7 million and a gain of $1.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.
As of December 31, 2008, we have not recorded any gain or loss associated with the planned sale of these assets; however on December 29, 2008, we entered into a definitive purchase and sale agreement with Adventure Exploration Partners, LLC (“Adventure”) which will result in estimated net proceeds of $17.6 million, after certain transaction costs and certain adjustments. We received a deposit in the amount of $1.8 million from Adventure which we have classified in Inventory, Prepaid Expenses and Other on our Consolidated Balance Sheets. Summarized financial information for discontinued operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the discontinued operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
Of the $18.9 million in assets that are classified as held for sale as of December 31, 2008, approximately 99.4% of this value is associated with property and equipment. Of the $26.4 million in assets that are classified as held for sale as of December 31, 2007, 100.0% of this value is associated with property and equipment. For the years ended December 31, 2008 and 2007, the amounts classified as liabilities related to assets held for sale are as follows:
5. PARTNERSHIP REDEMPTIONS
On March 12, 2007, New Albany entered into an Extension Agreement with its 50.0% member, Baseline Oil & Gas Corp. (“Baseline”). Under the terms of the Extension Agreement, Baseline was granted a one week extension to March 16, 2007 to pay a mandatory capital call issued by New Albany to Baseline in the amount of $492,000. In addition, the Extension Agreement provided that in the event Baseline paid New Albany an additional $1,729,000 in outstanding capital calls by March 16, 2007, New Albany would redeem Baseline’s 50.0% membership interest in New Albany pursuant to the terms of a mutually agreed upon redemption agreement. Under the terms of the form of redemption agreement, New Albany would agree that in exchange for the redemption of Baseline’s 50.0% membership interest in New Albany, New Albany would assign 50.0% of its assets, including its leasehold mineral interests, to Baseline. The Extension Agreement provided that in the event that Baseline failed to pay all outstanding capital calls by March 16, 2007, New Albany, and its non-defaulting members, would be entitled to exercise the rights set forth in Section 3.3(a) of New Albany’s limited liability company agreement dated November 25, 2005. Section 3.3(a) provides that in the event a member fails to pay certain mandatory capital calls issued by the managing member of New Albany, New Albany may permit other non-defaulting members to contribute the amount owed by the defaulting member as an additional capital contribution to New Albany. In such event, the membership interests of all members of New Albany will be adjusted pursuant to a formula, the numerator of which is the member’s total capital contributions to New Albany, and the denominator of which is the sum of all members’ total capital contributions to New Albany. The Extension Agreement further provided that in the event that Baseline’s membership interest in New Albany was reduced in the manner set forth above due to its failure to pay all of the outstanding capital calls, New Albany, under the terms of the Redemption Agreement, must immediately thereafter redeem Baseline’s interest in New Albany in exchange for the assignment to Baseline of an interest in all of New Albany’s assets equal to Baseline’s then reduced membership interest.
On March 16, 2007, Baseline paid to New Albany $300,000 of the outstanding capital calls owed to New Albany, leaving an unpaid capital call balance of $1,921,000. Immediately thereafter, in accordance with the terms of the Extension Agreement and Section 3.3.(a) of New Albany’s limited liability company agreement, Baseline’s membership interest in New Albany was reduced from 50.0% to 40.42%. Baseline and New Albany then entered into a redemption agreement providing that Baseline’s membership interest in New Albany was redeemed in exchange for an assignment by New Albany to Baseline of a 40.42% interest in all of New Albany’s assets, including its oil and gas leasehold interests. The value of the redemption was approximately $8.0 million. On March 16, 2007, pursuant to Section 3.3(a) of New Albany’s limited liability company agreement, Rex II elected to pay $3,157,000 to New Albany in satisfaction of its outstanding capital calls, as well as the unpaid outstanding capital calls of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner. In accordance with Section 3.3(a) of New Albany’s limited liability company agreement, the membership interests of the members were thereafter adjusted to reflect the additional capital
contributions made by Rex II on behalf of Baseline, Rex Energy Wabash, LLC, Shaner & Hulburt Capital Partners Limited Partnership and Lance T. Shaner, and the redemption of Baseline’s 40.42% membership interest. Following such adjustments, Rex II’s membership interest in New Albany was increased from 26.833% to 45.04%, Rex Energy Wabash, LLC’s membership interest was increased from 0.78% to 1.31%, Lance T. Shaner’s membership interest was increased from 17.93% to 30.09%, Shaner & Hulburt Capital Partners Limited Partner’s membership interest was increased from 2.94% to 4.93%, and Douglas Oil & Gas’s membership interest was increased from 11.10% to 18.63%.
6. CONCENTRATIONS OF CREDIT RISK
At times during the year ended December 31, 2008, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.
By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2008, we carried approximately $4.2 million in production receivable, of which approximately $2.5 million were production receivables due from a single customer, Countrymark Cooperative LLP. At December 31, 2007, we carried approximately $8.1 million in production receivable, of which approximately $5.4 million were production receivables due from a single customer, Countrymark Cooperative LLP. The growth in our Appalachian proved reserves helps to minimize our future risks by diversifying our number of purchasers.
7. COMMITMENTS AND CONTINGENCIES
Legal Reserves
At December 31, 2008, our Consolidated Balance Sheet included approximately $327,000 in reserve for the legal matters referenced in note 20-Litigation. At December 31, 2007, our Consolidated Balance Sheet included $384,000 in reserve for various legal proceedings. The accrual of reserves for legal matters is included in Accrued Expenses on the Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on our consolidated financial position or results of operations, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.
Drilling and Development
At December 31, 2008, we had three drilling commitments in our Appalachian Basin. The first commitment requires us to drill two natural gas wells each year for the next five years, beginning in 2008. We estimate an average investment in each well to be $1.9 million for a total five year drilling commitment of $19.0 million. Our second drilling commitment requires us to drill one natural gas well by December 11, 2009 at an estimated cost of $1.9 million. Our third drilling commitment requires that we build one well location and proceed with the drilling of one vertical test well, subject to rig availability, by September 2009 at an estimated cost of $1.9 million.
Leasing
At December 31, 2008, we had three installment payment commitments on mineral interests that were previously leased. The first commitment provides that we pay $350 per mineral acre for 5,722 acres, or a total commitment of $2.0 million, in 2012. The second commitment requires that we pay $250 per mineral acre for 5,761 acres, or $1.4 million, in each of the next four years for a total commitment of $5.8 million. The third commitment requires that we pay $350 per mineral acre for 762 acres, or $267,000, in each of the next four years for a total commitment of $1.1 million. These amounts have been recorded on the Consolidated Balance sheets as Other Deposits and Liabilities.
Environmental
Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort.
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except for contingent liabilities associated with the enforcement action initiated by the U.S. EPA and the class action litigation filed in the U.S. District Court of the Southern District of Illinois relating to alleged H2S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.
Contract Wells
In March 2004, we purchased from Standard Steel, LLC contractual rights associated with gas purchase contracts relating to 19 natural gas wells. Under the terms of the contracts, we buy 100.0% of production from these wells from third parties at contracted, fixed prices. The prices we pay may range from $1.10 per Mcf to 55.0% of the market price, plus a $0.10 per Mcf surcharge. There is no loss on these commitments. We have recorded the gross revenue and costs in the Consolidated and Combined Statements of Operations. We sell the natural gas extracted from these contract wells to parties unrelated to these natural gas wells and contracts.
Letters of Credit
We have posted $793,000, at December 31, 2008, in various letters of credit to secure our drilling and related operations.
Lease Commitments
At December 31, 2008 we have lease commitments for three different office locations. Rent expense has been recorded in General and Administrative expense as $285,000, $185,000 and $167,000 for the years ended December 31, 2008, 2007 and 2006, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).
Other
In addition to the asset retirement obligation discussed in note 2-Summary of Significant Accounting Policies, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts, totaling $302,000 and $322,000, are included in Other Deposits and Liabilities at December 31, 2008 and December 31, 2007, respectively.
8. RELATED PARTY TRANSACTIONS
At December 31, 2006, there was a working capital loan payable to Lance T. Shaner, our Chairman, in the amount of $1,820,000 from PennTex Illinois, one of the Predecessor Companies. At the time this loan was made, Mr. Shaner was the sole stockholder of PennTex Illinois. The loan was non-interest-bearing and was payable upon the demand of Mr. Shaner. In January 2007, the outstanding amount was satisfied through the conversion of $820,000 into an equity capital contribution into such Predecessor Company and the repayment of $1,000,000 to Mr. Shaner.
PennTex Resources repaid an outstanding debt to Mr. Shaner in the amount of $8,136,000 during the year ended December 31, 2006.
From September 2006 to May 2008, we leased an office building from Shaner Brothers, LLC, a Pennsylvania limited liability company (“Shaner Brothers”), which served as our headquarters in State College, Pennsylvania. Shaner Brothers is owned by Lance T. Shaner, our Chairman, and Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership controlled by Mr. Shaner. On September 1, 2006, Shaner Brothers loaned $264,656 to Rex Operating to fund expenses relating to the construction of the interior portions of the headquarters office building. This loan was evidenced by an unsecured promissory note dated September 1, 2006. The promissory note provided for the payment of interest on the unpaid principal sum at a rate of 7% per annum. The loan was required to be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240.50. The promissory note was to mature on September 1, 2011, but could be prepaid in whole or in part at anytime, without premium or penalty. We repaid this loan in its entirety on July 30, 2007 with proceeds from our initial public offering. On December 26, 2007, we entered into a new office lease agreement with an unrelated third party to lease approximately 16,000 square feet of office space to serve as our new headquarters in State College, Pennsylvania. We relocated to the new office space in May 2008 and Shaner Brothers thereafter terminated the office lease agreement, leased the office space to an unrelated third party and released us from any further obligations under the agreement.
Prior to April 2007, we received certain administrative services (such as information technology, human resources, benefit plan administration, payroll and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for reasonable out-of-pocket expenses. On April 10, 2007, we terminated our oral month-to-month administrative services agreement with Shaner Solutions. For the period covering January 1, 2007 to April 10, 2007 we paid Shaner Solutions $53,000 in relation to these services. For the year ended December 31, 2006, we paid $180,000 to Shaner Solutions in relation to these services. We believe that the amounts charged by Shaner Solutions were comparable to rates obtainable at an arm’s-length basis in the State College, Pennsylvania area for similar services.
In conjunction with the termination of our oral agreement with Shaner Solutions, we entered into an IT Consultation and Support Services Agreement, a Service Provider Agreement and a Tax Return Engagement Letter Agreement with Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Hotel”). Pursuant to the IT Consultation and Support Services Agreement, Shaner Hotel agreed to provide us with telecommunication, computer system and network administration, and information technology consultation services. Fees for the services provided under this agreement range from $55.00 to $125.00 per hour based upon the type and level of service provided, plus reimbursement for reasonable out-of-pocket expenses. The agreement continues until it is terminated by either party upon 90 days advance
written notice. Pursuant to the Service Provider Agreement, Shaner Hotel agreed to provide us with certain clerical and administrative support services in connection with the management and administration of our 401(k) retirement plan, payroll and employee health and welfare benefit plans. Under the agreement, we pay a fee of $95.00 per hour for any services performed by Shaner Hotel’s benefits manager and a fee of $55.00 per hour for services provided by other members of Shaner Hotel’s benefits department, plus reimbursement for reasonable out-of-pocket expenses. The term of the Service Provider Agreement is one year; however, either party may terminate the agreement upon 90 days advance written notice. Pursuant to the Tax Return Engagement Letter Agreement, Shaner Hotel agreed to provide us with certain tax planning and tax return preparation services. Fees for the services provided under this agreement range from $100.00 to $155.00 per hour based upon the tax expertise of the particular service provider, plus reimbursement for reasonable out-of-pocket expenses. The agreement continues until it is terminated by either party upon 90 days advance written notice. For the year ending December 31, 2008, we paid $71,000 to Shaner Hotels in relation to those services and $66,000 for the period covering April 10, 2007 to December 31, 2007. We believe that the amounts charged by Shaner Hotel are comparable to rates obtainable at an arm’s-length basis in the State College, Pennsylvania area for similar services. We have engaged a third-party to provide us with tax planning and preparation services and we have added information technology and benefit plan administration functions within the company. For these reasons, we do not expect to seek these services from Shaner Hotel in future and expect to terminate the agreements during 2009.
We currently have an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Mr. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate of $1,350 per hour. The hourly flight rate was adjusted in June 2008 to $3,000 per hour. The total monthly fixed costs for the airplane are currently approximately $26,000 per month. For the years ended December 31, 2008, 2007 and 2006, we paid Charlie Brown $74,000, $202,000 and $143,000 in relation to these services. We believe the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.
On June 21, 2007, we obtained a 24.75% limited partnership interest in Charlie Brown II Limited Partnership, a Delaware limited partnership (“Charlie Brown II LP”), and a 25% membership interest in its general partner, L&B Air LLC, a Delaware limited liability company (“L&B Air”). Charlie Brown II LP owned an Eclipse 500 Airplane, which it purchased for approximately $1,700,000. Shaner Hotel owned a 24.65% limited partnership interest in Charlie Brown II LP and a 25% membership interest in L&B Air, and Charlie Brown, an entity owned and controlled by Mr. Shaner, owned a 0.1% membership interest in Charlie Brown II LP. The remaining 49.50% limited partnership interest in Charlie Brown II LP and 50% interest in L&B Air were owned by an unrelated third party. On June 21, 2007, we made capital contributions to Charlie Brown II LP and L&B Air in the amount of $49,500 and $500, respectively. To fund these capital contributions, we borrowed $50,000 from Mr. Shaner. This loan was evidenced by a promissory note dated June 21, 2007 and bore interest at the rate of 7% per annum. The promissory note was payable upon the demand of Mr. Shaner and could be prepaid in whole or in part without penalty. We believe that the terms of this loan were comparable to terms that could be obtained at an arms’ length basis from unrelated lenders. We repaid this loan in its entirety on July 30, 2007 with proceeds from our initial public offering.
On June 21, 2007, Charlie Brown II LP and Charlie Brown entered into a First Amended and Restated Aircraft Joint Ownership and Management Agreement. Pursuant to this agreement, Charlie Brown agreed to provide certain aircraft management services, such as routine and scheduled maintenance, flight crew training, cleaning, inspections and flight operations and scheduling of the aircraft. In addition, Charlie Brown agreed to provide a flight crew for the operating of the aircraft and storage space in its hanger for storage of the aircraft. In exchange for these services, Charlie Brown II LP agreed to pay its proportionate share of Charlie Brown’s fixed costs, including crew, hanger and insurance costs, and a per hour flight charge to be determined by Charlie Brown consistent with current local market rates charged by similar flight operation companies.
On June 21, 2007, Charlie Brown II LP borrowed $1,530,000 from Graystone Bank. Proceeds from this loan were used to reimburse Mr. Shaner and an unrelated third party for a deposit they paid on behalf of Charlie Brown II LP in connection with the purchase of the Eclipse 500 airplane. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan requires payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II LP is required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The loan to Charlie Brown II LP was guaranteed by Mr. Shaner and the unrelated third party. For the years ended December 31, 2008 and 2007, we paid Charlie Brown II LP $69,000 and $9,000, respectively, for loan interest, services rendered and retainer fees.
On June 26, 2008, Charlie Brown II LP was converted to a Delaware limited liability company named Charlie Brown Air II, LLC, and on February 26, 2009, L & B Air merged into Charlie Brown Air II, LLC. Thereafter, our interests in Charlie Brown II LP and in L & B Air were converted to a twenty five percent (25%) membership interest in Charlie Brown Air II, LLC. In addition, the interests of Shaner Hotel and the unrelated third-party in Charlie Brown II LP and in L & B Air were converted to twenty five percent (25%) and fifty percent (50%) membership interests in Charlie Brown Air II, LLC, respectively.
The business affairs of Charlie Brown Air II, LLC are managed by three managers, appointed by each of its three members. We have designated Benjamin W. Hulburt, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of all managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.
Mr. Shaner is our Chairman and a significant stockholder of the company. Mr. Shaner’s ownership and association with Shaner Brothers, Shaner Solutions, Shaner Hotel, Charlie Brown, Charlie Brown Air II, LLC and us could create a conflict of interest between the interests of those entities and Mr. Shaner’s duties and obligations to us. The compensation for these arrangements and the purchase, leasing, financing, management and other arrangements between us and any Shaner affiliates may not be (to the extent permissible under applicable laws and regulations) a result of arm’s-length negotiations, and the relationships created by virtue of these arrangements may be subject to certain conflicts of interest. Our board of directors (with Mr. Shaner abstaining) performs a quarterly review of these contractual agreements, whether oral or written, and may continue, extend, amend or terminate any of these agreements.
9. LONG-TERM DEBT
Rex IV entered into a Credit Agreement dated as of October 2, 2006 with KeyBank National Association (“KeyBank”), as Administrative Agent on behalf of signatory lenders which are parties to the agreement from time to time. The credit facility established under the Credit Agreement provides for loans and letters of credit of up to a maximum of $40,000,000. On October 1, 2006, Rex IV borrowed $36,581,000 under the new credit facility to pay the purchase price for the acquisition of certain oil properties from Tsar Energy II, LLC.
On March 30, 2007, Rex IV and KeyBank executed a First Amendment to the Credit Agreement which extended the maturity date of borrowings under the credit agreement to the earlier of (i) the date of closing of our initial public offering or (ii) December 31, 2007. In addition, the First Amendment provided for a change in the interest rate per annum for Eurodollar borrowings to the London Interbank Offered Rate (“LIBOR”) plus 400 basis points. The First Amendment to the Credit Agreement also provided for revisions to certain negative
covenants contained in the credit agreement. The ratio of total debt to EBITDAX was changed from 5.75:1.00 to 7.00:1.00 for the fiscal quarter ending June 30, 2007, 6.75:1.00 for the fiscal quarter ending September 30, 2007 and 6.50:1.00 for the fiscal quarter ending December 31, 2007. The First Amendment also provided that for the purposes of calculating both ratios, EBITDAX excludes non-recurring legal expenses of Rex IV.
On July 24, 2007, Rex IV and KeyBank executed a Second Amendment to the Credit Agreement, which extended the maturity date of the credit agreement to the earlier of (a) the closing date of a new senior credit facility of the Company or (b) December 31, 2007. On July 31, 2007, we made a payment of approximately $27.8 million on this line of credit.
On July 31, 2007, we used the proceeds from the initial public offering to repay all credit facilities of the Predecessor Companies with the exception of the Rex IV line of credit. A payment of approximately $27.8 million on the Rex IV line of credit was made resulting in remaining indebtedness on the line of approximately $14.6 million as of July 30, 2007. The remaining balance on the Rex IV line of credit was subsequently repaid with borrowings from our new senior-secured line of credit.
On September 28, 2007, we entered into a new credit agreement with KeyBank, as Administrative Agent; BNP Paribas, as Syndication Agent;, Sovereign Bank, as Documentation Agent; and lenders from time to time parties thereto (the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base is $75 million; however, the Senior Credit Facility provides that the revolving credit facility may be increased up to $200 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. Within that borrowing base, outstanding letters of credit are permitted up to $10 million. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. At our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to (a) LIBOR for one, two, three, six or nine months (“Adjusted LIBOR”) plus an applicable margin ranging from 100 to 175 basis points plus a commitment fee ranging from 25 to 37.5 basis points, or (b) the higher of KeyBank’s announced prime rate (“Prime Rate”) and the federal funds effective rate from time to time plus 0.5% in each case, plus an applicable margin ranging from 0 to 25 basis points plus a commitment fee ranging from 25 to 37.5 basis points. Interest is payable on the last day of each relevant interest period in the case of loans bearing interest at the Adjusted LIBOR and quarterly in the case of loans bearing interest at the Prime Rate. The average interest rate on our Senior Credit Facility at December 31, 2007 was approximately 6.8%, before the effect of interest rate hedging. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. On or before March 1 and September 1 of each year, we are required to furnish to the lenders a reserve report evaluating our oil and gas properties as of the immediately preceding January 1 and July 1. The reserve report as of January 1 of each year must be prepared by one or more independent petroleum engineers approved by the Administrative Agent. Any re-determined borrowing base will become effective on the subsequent April 1 and October 1. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base.
On April 14, 2008, we entered into a First Amendment to the Senior Credit Facility (the “First Amendment”). The First Amendment provides that the borrowing base under the Senior Credit Facility is increased from $75 million to $90 million effective April 14, 2008. The increased borrowing base will remain in effect until the next borrowing base re-determination date. The First Amendment also amends the Senior Credit Facility to provide that, upon an increase in the borrowing base, we will pay to the lenders a borrowing base increase fee equal to 25 basis points on the amount of any increase of the borrowing base over the highest borrowing base previously in effect, payable on the effective date of any such increase. In addition, the First
Amendment amends the Senior Credit Facility with respect to our ability to enter into commodity and swap agreements. The First Amendment provides that we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. Prior to the First Amendment, the volumes for commodity swap agreements under the Senior Credit Facility could not exceed, as of the date the swap agreement was executed, 75% of the reasonably anticipated projected production from our proved developed producing reserves, for each of crude oil and natural gas for each month during the period in which the swap agreement was in effect for each of crude oil and natural gas, calculated separately.
The First Amendment also amends the Senior Credit Facility to provide that we may enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. Prior to the First Amendment, our interest rate swap agreements under the Senior Credit Facility were limited to 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.
On January 5, 2009, we entered into a Second Amendment to the Senior Credit Facility effective December 23, 2008 (the “Second Amendment”) with KeyBank, as Administrative Agent, and other lenders. The Second Amendment provides that the borrowing base under our Senior Credit Facility of $90 million will remain in effect until the next borrowing base re-determination date; provided that if we complete the sale of our Southwest Region assets before such date, upon such sale, the borrowing base will be reduced to $80 million. In addition, the Second Amendment amends the Senior Credit Facility to amend the definition of “Alternate Base Rate”. The Second Amendment provides that the “Alternate Base Rate” means, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1% and (c) (i) LIBOR plus (ii) the Applicable Margin for Euro Dollar Loans minus (iii) the Applicable Margin for ABR Loans each on such day. Prior to the Second Amendment, “Alternate Base Rate” meant, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1%.
We pledge our oil and natural gas properties as collateral under the Senior Credit Facility and are subject to certain financial covenants. The first of such covenants states that as of the last day of any fiscal quarter, our ratio of EBITDAX for the period of four fiscal quarters ending on such day to interest expense for such period is to be less than 3.0 to 1.0. Additionally, as of the last day of any fiscal quarter our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day is to be greater than 4.0 to 1.0. The last covenant states that as of the last day of any fiscal quarter, our ratio of consolidated current assets as of such day to consolidated current liabilities as of such day is to be less than 1.0 to 1.0. As of December 31, 2008, we were in compliance with all of our debt covenants.
In addition to our Senior Credit Facility, we may, from time to time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consists of the following at December 31, 2008 and 2007:
The terms of the Senior Credit Facility require that we make monthly payment of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans.
The following is the principal maturity schedule for debt outstanding as of December 31, 2008 ($ in thousands):
10. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard 107, Disclosures About Fair Value of Financial Instruments (“SFAS 107”). We have determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
Financial instruments include cash and cash equivalents, receivables, payables, commodity and interest rate derivatives. The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of our long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.
The fair value associated with our derivative instruments from continuing operations was an asset of approximately $14.2 million and a liability of $29.7 million at December 31, 2008 and 2007, respectively. The fair value is based on valuation methodologies of our counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we entered into oil and natural gas commodity derivative instruments. As of December 31, 2008 and December 31, 2007, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts and collars. These instruments do not qualify as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense.
Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a calculation period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.
We enter into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with each of these counterparties. We do not obtain collateral to support the agreements, but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions.
We sell oil and natural gas in the normal course of business and utilize derivative commodity instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales.
We incurred net payments of $16.2 million, $6.2 million and $4.4 million under these commodity derivative instruments during years ended December 31, 2008, 2007 and 2006, respectively. These net payments are included in Operating Revenue on our Consolidated and Combined Statement of Operations. Unrealized gains (losses) associated with these derivative instruments from continuing operations are included in other income (expense) and amounted to $43.7 million, ($26.3) million and $5.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Our open asset/ (liability) financial commodity derivative instrument positions at December 31, 2008 consisted of:
As of December 31, 2008, we had entered into an interest rate swap derivative instrument which hedged our interest rate risk associated with changes in LIBOR on $20,000,000 of notional value. We use the interest rate swap agreement to manage the risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. The interest rate under the swap is 4.15% and the agreement expires in November 2010. The fair value of the swap at December 31, 2008 was a liability of $1,171,000, an increase of $964,000 since December 31, 2007, based on current LIBOR quotes. On June 30, 2008, the interest rate swap was considered to be ineffective. We have accounted for the hedge by recording the $964,000 unrealized loss for the twelve months ended December 31, 2008 as a decrease to Unrealized Gain (Loss) on Derivatives on our Consolidated and Combined Statement of Operations.
Adoption of SFAS 157
Effective January 1, 2008, we adopted SFAS 157, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy defined by SFAS 157 are as follows:
Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Level 2-Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Level 3-Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2008, we have no significant Level 3 measurements.
The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS ($ in thousands):
As noted in note 2-Summary of Significant Accounting Policies, as permitted by FSP 157-2, we deferred the provisions of SFAS 157 for nonfinancial assets and nonfinancial liabilities until January 1, 2009.
11. INCOME TAXES
We account for income taxes in accordance with the provisions of Statement of Financial Accounting Standards 109, Accounting for Income Taxes (“SFAS 109”). This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax
rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We recognized deferred tax assets and liabilities upon the consummation of the Reorganization Transactions and acquisition of minority interests. Before these events, the Predecessor Companies were pass-through entities that did not pay income taxes and did not reflect deferred tax assets and liabilities.
The Predecessor Companies were treated as partnerships or subchapter S corporations for federal and state income tax purposes. Accordingly, income taxes were not reflected in the combined financial statements because the resulting profit or loss was included in the income tax returns of the individual stockholders, members or partners. Accordingly, we did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. Income tax expense has been provided for on our Consolidated and Combined Statement of Operations prospectively for periods after August 1, 2007.
All information in the tables below includes results from continuing operations and discontinued operations.
A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:
(a) At December 31, 2008, we reclassified approximately $298,000 of net income before minority interests and income taxes to accounts payable. As a result of the effective date of the sale of our Southwest Region properties being determined as October 1, 2008, this amount represents the income for the three month period ending December 31, 2008, that is due to the purchaser of our Southwest Region properties. This amount is not recognizable as income for book purposes; however it is required to be recognized as income for tax purposes.
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The combined Predecessor Companies at December 31, 2006 consisted of limited liability partnerships, limited liability companies, and subchapter S corporations whose taxable income (loss) passed to the various members, partners, and stockholders in those respective entities. Accordingly, no deferred tax liabilities or assets were recognized by those entities at December 31, 2006. Deferred tax liabilities (assets) are comprised of the following at December 31, 2008 and 2007.
Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2008, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it is now more than likely than not that these deferred tax assets will likely be realized in the future. Accordingly, we determined that it is appropriate to present our deferred tax assets without a valuation allowance.
Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.
At December 31, 2008, we had available unused net operating loss carryforwards that may be applied against future taxable income that expire as follows ($ in thousands):
Effective August 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109, Accounting for Income Taxes (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Our practice is to recognize interest related to income tax expense in Interest Expense and penalties in General and Administrative expense. We did not have any accrued interest or penalties as of December 31, 2008 and 2007.
We also adopted FASB Staff Position FIN 48-1, Definition of Settlement in FASB Interpretation 48 (“FSP FIN 48-1”) as of August 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal and it is remote that the taxing authority would reexamine the tax position in the future.
The adoption of FIN 48 and FSP FIN 48-1 had no significant effect on our financial position, results of operations or cash flows.
FIN 48 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FIN 48 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FIN 48 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.
Our management has concluded that, as of December 31, 2008, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions.
We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States Federal jurisdiction and in many state jurisdictions. We are subject to U.S. Federal income tax examinations and to various state tax examinations for periods after August 1, 2007.
12. CAPITAL STOCK
Currently, our common stock is traded on the NASDAQ global market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. In July 2007, we completed our initial public offering of 9,600,000 shares of common stock at $11.00 per share. In May 2008, we completed a public offering of 5,775,000 shares of common stock at an offering price of $20.75 per share. As of December 31, 2008, we had 36,569,712 shares of common stock outstanding.
13. MAJOR CUSTOMERS
PennTex Illinois, PennTex Resources, Rex I, LLC. and Rex IV sold 100.0% of their oil production in the Indiana and Illinois fields to Countrymark Cooperative LLP. The total amount of oil sold to Countrymark Cooperative, LLP in 2008, 2007 and 2006 was approximately $74.0 million, $52.2 million and $27.7 million, respectively. These sales represent 88.1%, 89.8% and 71.4%, respectively, of total oil and natural gas sales.
14. EMPLOYEE BENEFIT AND EQUITY PLANS
401(k) Plan
We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan were approximately $272,000, $204,000 and $185,000 for the years ended December 31, 2008, 2007 and 2006, respectively. We paid approximately $8,000 of expenses per year on behalf of the 401(k) plan for the years ended December 31, 2008, 2007 and 2006, respectively.
Equity Plans
In December 2004, the FASB issued SFAS 123(R), Share-Based Payment (“SFAS 123R”), which is a revision of SFAS 123, Accounting for Stock Based Compensation (“SFAS 123”). SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their grant-date fair values, using prescribed option-pricing models. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period.
Effective August 1, 2007, we adopted SFAS 123R’s fair value method of accounting for share-based. Prior to August 1, 2007, we did not have any share-based payments to employees or directors.
SFAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under previous literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. There were no tax benefits recognized in 2008, 2007 or 2006.
2007 Long-Term Incentive Plan
We have granted stock options, stock appreciation rights and restricted stock awards to various employees and non-employee directors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the compensation committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees, intend to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.
All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.
Stock Options
During the year ended December 31, 2008, the Compensation Committee awarded grants of 516,200 nonqualified stock options to 23 employees and four non-employee directors. During the year ended December 31, 2007, the Compensation Committee awarded grants of 825,000 nonqualified stock options to 25 employees and four non-employee directors. The nonqualified stock options granted to our employees have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the option holder remains our employee until that date. The nonqualified stock options granted to our non-employee directors have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable in one-third increments on the first, second and third year anniversaries of the date of grant. All options also provide that all unvested options vest and become immediately exercisable upon a “change in control” of us; as such term is defined in the Plan.
Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan.
A summary of the stock option activity is as follows:
Stock-based compensation expense relating to stock options for the years ended December 31, 2008, 2007 and 2006 totaled $3.0 million, $0.2 million and $0, respectively. The expense related to stock option grants was recorded on our Consolidated and Combined Statements of Operations under the heading of General and Administrative expense.
The total number of options granted in 2008 and 2007 were 516,200 and 825,000, respectively. The fair value of each option grant is estimated on the date of the grant using the Black-Scholes option-pricing model with the following assumptions:
The dividend yield of zero is based on the fact that we have never paid cash dividends on common stock and have no present intention of doing so. Our expected historical volatility factor was determined by assessing the common stock trading history of eight publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the options. The average expected life has been determined using the “simplified method” as referenced in SEC Staff Accounting Bulletin 107 (“SAB 107”) and SEC Staff Accounting Bulletin 110 (“SAB 110”), in which the average expected life of the option is equal to the average of the term of the option and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options. We used an estimated forfeiture rate of 17.7% in 2008 for calculating stock-based compensation expense related to stock options and this rate is based on historical experience. In 2007, we elected to use the simplified method for determining the average expected life because we did not have a reliable history on which to base estimates for future forfeiture rates.
Based on the above assumptions, the weighted average estimated fair value of options granted during the years ended December 31, 2008, 2007 and 2006 was $9.35 per share, $5.00 per share and $0.00 per share, respectively. The weighted average exercise price of options granted during 2008, 2007 and 2006 was $21.50, $9.90 and $0 per share, respectively.
A summary of the status of our issued and outstanding stock options as of December 31, 2008 is as follows:
The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2008 were 8.10 years and $0, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at December 31, 2008 were 8.85 years and $0, respectively. As of December 31, 2008, unrecognized compensation expense related to stock options totaled approximately $4.4 million, which will be recognized over a weighted average period of 1.98 years.
Stock Appreciation Rights
During the year ended December 31, 2008, the Compensation Committee awarded 109,500 stock appreciation rights (“SARs”) to five employees and there were no awards in 2007. SARs represent the right to receive cash or shares of common stock in the future equivalent to the difference between the fair market value at the time of exercise and the strike price. The SARs have an exercise price equal to $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the holder remains our employee until that date. The SARs also provide that all unvested SARs vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan. The outstanding SARs issued as of December 31, 2008 may only be exercised for cash settlement. As of December 31, 2008, unrecognized compensation expense related to SARs totaled approximately $34,000.
Restricted Stock Awards
During the year ended December 31, 2008, the Compensation Committee issued 20,000 shares of restricted common stock to one employee, with all restrictions on transfer associated with such shares scheduled to terminate in May 2013. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Market on the date of the grant. Restrictions on the transfer associated with vesting schedules are determined by the Compensation Committee on an individual award basis. The restrictions on the stock lapse immediately upon a “change in control” of us, as such term is defined in the Plan. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period. As of December 31, 2008, total unrecognized compensation cost related to the restricted common stock grant was approximately $400,000.
A summary of the restricted stock activity for the year ended December 31, 2008 is as follows ($ in thousands except per share data):
15. SUSPENDED EXPLORATORY WELL COSTS
We follow FASB Staff Position 19-1, Accounting for Suspended Well Costs (“FSP FAS 19-1”), which permits the continued capitalization of exploratory well costs if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
The following table reflects the net change in capitalized exploratory well costs, excluding those related to our Southwest Region properties which are currently classified as Held for Sale on our Consolidated Balance Sheets, for the years ended December 31, 2008, 2007 and 2006 ($ in thousands):
The $1.4 million in capitalized well costs that have been capitalized for a period of greater than one year were incurred in 2007. These costs all relate to our ASP project in the Illinois Basin. We are undergoing an analysis of various stimulation techniques to determine if economic quantities of crude oil can be produced from this project.
16. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES
Costs incurred in oil and natural gas property acquisitions and development are presented below:
Property acquisition costs include costs incurred to purchase, lease or otherwise acquire property as well as capitalized future abandonment costs. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat and gather natural gas and oil.
17. OIL AND NATURAL GAS CAPITALIZED COSTS
Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below.
18. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)
Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) and Schlumberger Consulting and Data Services (“Schlumberger”), have evaluated our proved oil and natural gas reserves for the years ended December 31, 2008, 2007 and 2006. Schlumberger evaluated the proved reserves on our Marcellus Shale properties while NSAI evaluated the proved reserves on all of our other properties. We emphasize that reserve estimates are inherently imprecise. Our oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our proved reserves are located within the United States.
Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable accuracy will be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and oil and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.
Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2008, 2007 and 2006. The reserves are proved and exclude reserves associated with our Southwest Region properties that are shown as Assets Held for Sale on our balance sheet. The total proved reserves for these assets at December 31, 2008, 2007 and 2006 were 1,234,698, 1,300,917 and 1,015,467, respectively.
19. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
SFAS 69, Disclosures About Oil and Gas Producing Activities, (“SFAS 69”), prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.
The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by SFAS 69 at December 31, 2008, 2007 and 2006 ($ in thousands) and exclude reserves related to our Southwest Region properties that are shown as Assets Held for Sale on our Consolidated Balance Sheets:
(a) Calculated using weighted average prices of $5.71 per Mcf and $41.00 per barrel of oil
(b) Calculated using weighted average prices of $6.79 per Mcf and $92.50 per barrel of oil
(c) Calculated using weighted average prices of $5.64 per Mcf and $57.75 per barrel of oil
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
(a) At December 31, 2008, the tax basis of our assets exceeded the future cash flows of our oil and gas properties, which indicates that no future income taxes will be paid. Impairment testing was performed on our oil and gas properties at year end based on escalating future oil and natural gas prices. The standardized measure of discounted future net cash flows is based on the year end SEC commodity prices, which are held constant for the life of the properties.
20. LITIGATION
PennTex Illinois-ERG v. Tsar Energy II, LLC
At December 31, 2006, PennTex Illinois was involved in a lawsuit with Tsar Energy II, LLC (“Tsar”) and Richard A. Cheatham (“Cheatham”) in the 334th Judicial District Court of Harris County, Texas (the “Tsar Case”). The dispute centered around overhead fees charged by PennTex Illinois as operator of jointly-owned oil producing properties located in Illinois and Indiana in which PennTex Illinois owns a 26.0% working interest. Tsar then owned a 49.0% non-operator working interest in the subject properties. PennTex Illinois (then known as ERG Illinois, Inc.) and its former owner, Scott Y. Wood (“Wood”), commenced this litigation in July 2004, by filing a petition against Tsar and its president, Cheatham, seeking, among other things, a declaratory judgment that PennTex Illinois, as the operator of the subject properties, was entitled to charge Tsar and the other non-operators their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit portion of the properties pursuant to the terms of an operating agreement relating to such unit.
Tsar filed counterclaims against PennTex Illinois (then known as ERG Illinois, Inc.) asserting (i) a breach of contract and declaratory judgment claim seeking an unspecified amount of actual damages along with declaratory relief based on allegations that PennTex Illinois breached both the joint operating agreement covering the properties in question and a March 2004 letter of intent that preceded it by charging Tsar its proportionate share of a fixed monthly overhead charge of $300 for each producing well located in the North Lawrence Unit portion of the subject properties, (ii) breach of contract claim seeking $100,000 in actual damages based on Tsar’s allegation that PennTex Illinois breached a verbal agreement between the parties relating to an extension fee, (iii) a claim seeking an unspecified amount of actual and punitive damages based on Tsar’s assertion that PennTex Illinois committed fraud in the inducement in connection with Tsar’s acquisition on March 16, 2004 of its 49.0% non-operating working interest in the subject properties by allegedly making false representations before and in the letter of intent executed by PennTex Illinois and Tsar and (iv) a conversion claim seeking actual damages of $100,000, plus an unspecified amount of punitive damages, based on Tsar’s allegations that PennTex Illinois improperly converted funds belonging to Tsar.
On December 22, 2005, PennTex Illinois filed a motion for summary judgment regarding the principal contract claims at issue and the tort counterclaims that had been asserted against it by Tsar. By order signed February 8, 2006, the court granted the PennTex Illinois’ motion for summary judgment sustaining its right to charge the non-operators of the subject properties their proportionate shares of a fixed monthly overhead charge of $300 for each producing well located within the North Lawrence Unit. By the same order, the court denied PennTex Illinois’ motions for summary judgment seeking dismissal of Tsar’s fraud in the inducement and conversion counterclaims. On March 3, 2006, PennTex Illinois and Tsar jointly moved to sever into a separate action, the claims and counterclaims relating to PennTex Illinois’ charging of fixed monthly overhead on producing wells in the North Lawrence Unit so that the court would be able to sign a final, appealable judgment in PennTex Illinois’ favor on the issues resolved by the court’s summary judgment ruling. The court granted this joint motion on March 3, 2006 and the severed action was docketed in the district court as a severed case. On March 31, 2006, Tsar appealed the district court’s final judgment in the severed action to the Court of Appeals First District of Texas.
On October 3, 2006, Rex Energy IV acquired the 49.0% working interest of Tsar in the Illinois and Indiana properties at issue in the above cases. As part of this transaction, and without payment of any separate consideration, PennTex Illinois obtained a written settlement agreement requiring Tsar and its principal, Cheatham, to dismiss with prejudice the claims that they had asserted against PennTex Illinois in both the severed and non-severed actions, and to deliver a mutual release releasing PennTex Illinois and certain other affiliates of PennTex Illinois from any and all liability for claims that had been asserted (or could have been asserted) in the two cases by Tsar and Cheatham. Pursuant to this settlement agreement, the claims asserted against PennTex Illinois in the non-severed action were dismissed with prejudice by an order signed on October 5, 2006. On October 26, 2006, the claims asserted against PennTex Illinois in the severed action were
dismissed with prejudice by the Court of Appeals First District of Texas, thereby bringing to a final conclusion not only the appellate case, but the underlying severed district court case from which the appeal had been brought.
PennTex Illinois-Tsar’s Audit Exceptions Claim
On February 1, 2006, PennTex Illinois was served with a draft audit report prepared by an outside auditor retained by Tsar to audit the joint interest billings that were made by PennTex Illinois. The time period of the audit report was March 1, 2004 through June 30, 2005. The audit report purported to identify potential audit exception claims totaling $17,269,956, plus additional unspecified amounts to be determined.
On February 3, 2006, Tsar filed a formal non-suit without prejudice to its breach of contract counterclaim asserted against PennTex Illinois in the Tsar Case that had sought to recover damages if an accounting of the charges to the joint account revealed that they were inaccurate. On July 31, 2006, PennTex Illinois submitted to Tsar its written response to Tsar’s audit report. PennTex Illinois’ response alleged that the majority of the audit exceptions set forth in the audit report were unsupported, not evidenced by true audit work, based on supposition and hearsay, and not presented in the manner required by applicable guidance of the Council of Petroleum Accounting Societies (“COPAS”). The majority of the audit exceptions set forth in the report were denied by PennTex Illinois; however, PennTex Illinois identified costs and expenses totaling $106,616 which were owed to PennTex Illinois by Tsar.
In connection with the settlement of the Tsar lawsuit, PennTex Illinois, without payment of any separate consideration, obtained a full and complete release of the audit exception claims asserted by Tsar in its audit report dated February 1, 2006. This release, which was executed by Tsar on October 3, 2006, was obtained pursuant to the acquisition transaction pursuant to which Rex Energy IV acquired the working interest of Tsar in the jointly-owned oil producing properties located in Illinois and Indiana.
PennTex Resources-Wood Arbitration and Confirmation of Arbitration Award
PennTex Resources is a litigant in an appeal in the United States Court of Appeals for the Fifth Circuit entitled “Scott Y. Wood v. PennTex Resources, L.P., Case No. 08-20462.” The case is an appeal of a final judgment that was signed on June 27, 2008 by the United States District Court for the Southern District of Texas, Houston Division. The final judgment confirmed an award issued by an arbitration panel convened by the American Arbitration Association in Houston, Texas. This was a binding arbitration proceeding that was commenced on June 21, 2006, by PennTex Resources and our Chairman, Lance T. Shaner (“Shaner”), against ERG Illinois Holdings, Inc. (“ERG Holdings”) and its sole stockholder, Scott Y. Wood (“Wood”), pursuant to the dispute resolution provisions of a stock purchase agreement that was entered into in January 2005 by Wood’s company, ERG Holdings, as “Seller,” and PennTex Resources, as “Buyer” (the “2005 Stock Purchase Agreement”). The principal claim in the arbitration proceeding was PennTex Resources’ and Shaner’s claim that ERG Holdings and Wood should be ordered to comply with a “claim release obligation” contained in the 2005 Stock Purchase Agreement that required Wood, under certain designated circumstances, to dismiss or release the individual claims that he was prosecuting against Tsar and Cheatham (the “Tsar Case”). PennTex Resources became obligated to file this arbitration proceeding seeking to enforce Wood’s “claim release obligation” by reason of an agreement that PennTex Illinois and PennTex Resources entered into on March 2, 2006 with Tsar and Cheatham in order to resolve certain procedural issues relating to the Tsar Case.
PennTex Resources and/or Shaner also filed the following additional claims in the arbitration proceeding: (a) a claim against ERG Holdings seeking an award of $383,760, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate post-closing purchase price adjustment under the 2005 Stock Purchase Agreement; (b) a claim against ERG Holdings seeking an award of approximately $20,000, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of a contractual obligation to return the original and all copies of a letter of credit posted by PennTex Resources to
secure its indemnity obligations under the 2005 Stock Purchase Agreement, which breach was alleged to have wrongfully caused PennTex Resources to have had to unnecessarily incur an annual renewal fee to keep such letter of credit in force and (c) a claim against ERG Holdings seeking an award of approximately $23,500, plus pre-award interest and attorneys’ fees, based on ERG Holdings’ alleged breach of its obligation to make an appropriate pre-closing purchase price adjustment to reflect in its final closing statement an existing liability owed to the owners of a net profits interest relating to certain leases within the Lawrence Field.
On June 30, 2006, Wood filed suit against PennTex Resources and Shaner in the United States District Court for the Southern District of Texas, Houston Division, seeking to obtain a declaratory judgment that Wood could not be compelled to participate in the arbitration proceeding on the grounds that he was not a signatory to the 2005 Stock Purchase Agreement. On August 1, 2006, PennTex Resources and Shaner filed an answer and counterclaim asserting that the action should be stayed, and that Wood should be compelled to proceed to arbitration in the pending arbitration proceeding. On October 23, 2006, the court issued an order granting PennTex Resources’ and Shaner’s motion to compel arbitration. On November 2, 2006, the court signed an order staying the action and administratively closing it pending the determination of the final award in the underlying arbitration proceeding.
On January 22, 2007, Wood and ERG Holdings filed a response in the arbitration proceeding disputing the standing of Shaner and PennTex Resources to participate in the arbitration and denying all claims made by the claimants. In addition, ERG Holding asserted a counterclaim against PennTex Resources for a post-closing adjustment in the purchase price under the 2005 Stock Purchase Agreement in its favor in the amount of $182,865. In February 2007, Wood brought a counterclaim against PennTex Resources in the amount of $171,351 for attorney’s fees and expenses incurred by Wood in the Tsar Case alleging that PennTex Resources was required to reimburse Wood for such fees and expenses under the 2005 Stock Purchase Agreement. The arbitration panel of the American Arbitration Association held a final hearing in the arbitration proceeding on June 25 and 26, 2007. On June 25, 2007, at his request and without objection by Wood or ERG Holdings, the panel dismissed Shaner as a claimant in the arbitration. In addition, PennTex Resources withdrew its claim for the $23,500 pre-closing purchase price adjustment.
On August 20, 2007, the arbitration panel issued its findings and awards in the arbitration proceeding. The panel awarded Wood the amount of $92,540 for attorneys’ fees and expenses incurred by Wood relative to prosecuting his counterclaims in the Tsar Case. The panel found or awarded PennTex Resources the following: (a) with respect to its claim for post-closing purchase price adjustments under the 2005 Stock Purchase Agreement, (b) ERG Holdings and Wood were required to return the original and all copies of the $1,000,000 letter of credit previously provided by PennTex Resources pursuant to the 2005 Stock Purchase Agreement and ordered not to draw upon or attempt to draw upon the letter of credit conditioned upon PennTex Resources’ payment of Wood’s attorney’s fees and expenses related to his counterclaims in Tsar Case, (c) Wood was required to promptly provide PennTex Resources with a signed release or dismissal of his claims filed in the Tsar Case, (d) Wood was ordered to pay PennTex Resources $217,429 in attorney’s fees relating to the federal court litigation that required Wood to appear before the arbitration panel and its release obligation claim, (e) ERG Holdings was ordered to pay PennTex Resources $67,878 for attorneys fees and expenses incurred by PennTex Resources in pursuing its claims against ERG Holdings, (f) Wood was ordered to pay PennTex Resources $14,302 for expenses incurred by PennTex Resources relative to the arbitration proceeding, (g) ERG Holdings was ordered to pay PennTex Resources $7,368 for expenses incurred relative to the arbitration proceeding and (h) Wood and ERG Holdings were ordered to reimburse PennTex Resources the sum of $3,625 for fees and expenses of the American Arbitration Association. As a result of the arbitration panel’s award, Wood was required to pay PennTex Resources a total of $141,003 (after deducting legal fees and expenses payable by PennTex Resources to Wood in the amount of $92,540 relative to Wood’s counterclaims in the Tsar Case) and ERG Holdings was required to pay PennTex Resources a total of $165,835, thus resulting in a total cash award to PennTex Resources of $306,839.
On September 13, 2007, PennTex Resources filed a motion in the district court seeking confirmation of the arbitration award. On October 11, 2007, Wood filed a motion seeking to vacate the arbitration award on grounds
that the arbitration panel exceeded its powers by issuing a decision based upon clearly erroneous findings of fact. On June 27, 2008, the United States District Court issued a Memorandum and Order confirming the commercial arbitration award and denying Wood’s motion to vacate the award. The order also granted PennTex Resource’s request to offset monetary judgments of the opposing parties set forth in the award, but denied PennTex Resource’s motion for sanctions against Wood’s attorney.
On September 8, 2008, Wood filed an appeal with the United States Court of Appeals for the Fifth Circuit requesting the appellate court to reverse the district court’s decision compelling Wood to participate in the arbitration proceeding and its order confirming the arbitration award. ERG Holdings did not join in Wood’s appeal, and therefore, a final judgment was entered against ERG Holdings in favor of PennTex Resources. In connection with his appeal, Wood deposited into the registry of the district court an amount equal to the judgment against him. On October 10, 2008, PennTex Resources filed its response brief opposing Wood’s appeal and requesting the appellate court to affirm the district court’s final judgment against Wood. The United States Court of Appeals for the Fifth Circuit held oral argument for the appeal on March 4, 2009. We intend to vigorously oppose Wood in his appeal and we believe that the likelihood of an unfavorable outcome of this matter is remote.
PennTex Illinois and Rex Operating-EPA Enforcement Matter
In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against PennTex Illinois and Rex Operating seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H2S) gas and other volatile organic compounds (“VOC’s”) in the course of the companies’ oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. The companies’ senior management and representatives of the U.S. EPA, U.S. DOJ, Illinois Environmental Protection Agency (“Illinois EPA”) and the Agency for Toxic Substances and Disease Registry (“ATSDR”) attended a meeting at the offices of the U.S. EPA in Chicago, Illinois on September 7, 2006, to discuss matters relating to the enforcement action. This meeting had been preceded by certain monitoring of air emissions in the areas surrounding Bridgeport, Illinois and Petrolia, Illinois that the U.S. EPA and ATSDR had conducted in May 2006.
As a result of the initial meeting with the government on September 7, 2006, and certain subsequent meetings and communications with the U.S. EPA and U.S. DOJ, PennTex Illinois and Rex Operating executed a non-binding agreement in principle with the U.S. EPA effective October 24, 2006. In the agreement in principle, PennTex Illinois and Rex Operating agreed to develop and carry out a written response plan designed to further reduce possible emissions of H2S and VOC’s from the companies’ oil wells and facilities in the Lawrence Field that are closest to populated areas. The companies agreed to operate and maintain the control measures described in the response plan in accordance with a written operations and maintenance plan to be developed by the companies and approved by the U.S. EPA. The agreement in principle also required the companies to evaluate the effectiveness of the control measures in the Lawrence Field installed pursuant to the response plan through a monitoring program, and required them to evaluate the need for additional control measures at other facilities within the Lawrence Field within 60 days. The companies also agreed to present to the U.S. EPA any recommendations for further action the companies might develop based upon their observations of the effectiveness of the control measures. The parties each agreed that they would use their best efforts to negotiate a proposed final settlement agreement that would resolve the government’s enforcement action, which settlement agreement would be published in the Federal Register and made subject to public comment before any final approval.
On April 4, 2007, PennTex Illinois, Rex Operating and the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability and without any agreement to pay any civil fine or penalty, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field. Under
the terms of the proposed consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H2S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia. A notice regarding the proposed consent decree was published in the Federal Register on April 19, 2007. The published notice of the proposed consent decree solicited public comments on the terms of the consent decree for a 30 day period expiring on May 21, 2007. The United States did not receive any comments on the proposed consent decree during the public comment period. On June 1, 2007, the United States filed a motion for the approval and entry of the proposed consent decree with the United States District Court for the Southern District of Illinois. On June 6, 2007, the court granted the United States’ motion for approval and entry of the proposed consent decree, thereby resolving the enforcement action according to the terms described in the consent decree. The consent decree does not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.
As of December 31, 2008, we have substantially met all requirements of the consent decree. In a letter dated February 8, 2008, the U.S. EPA, in consultation with the Illinois EPA, approved our proposed plan and schedule for implementing our H2 S control measures in the Lawrence Field. Throughout 2008, we implemented the operating and maintenance procedures and completed the installation of all control measures in accordance with the schedule approved by the U.S. EPA.
PennTex Illinois and Rex Operating-H2S Class Action Litigation
PennTex Illinois and Rex Operating are defendants in a class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois. This action was commenced on October 17, 2006, by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H2S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint was amended in March 2007 to add a claim for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. PennTex Illinois and Rex Operating have filed a joint answer to the amended complaint denying virtually all of the allegations in the amended complaint and asserting affirmative defenses thereto.
On December 20, 2006, the plaintiffs filed a motion for class certification requesting that the court certify the case as a class action. On January 26, 2007, the court issued a scheduling and discovery order establishing deadlines for completing discovery and briefing relating to the plaintiffs’ motion for class certification. The original order provided for an August 2007 deadline for the completion of pre-certification discovery and the filing of the last brief on class certification issues; however, in August 2007, and again in October 2007, the scheduling and discovery order was amended to extend these deadlines to January 2008. The parties to the lawsuit exchanged initial pretrial disclosures as required under the applicable rules, and each side served and responded to pre-deposition written discovery. In addition, the defendants deposed each of the named plaintiffs and each of the plaintiffs’ expert witnesses offered in support of the plaintiffs’ motion for class certification. The plaintiffs did not elect to depose the defendants’ expert witnesses offered in support of their opposition to class certification.
The plaintiffs filed an amended motion for class certification on January 22, 2008. PennTex Illinois and Rex Operating filed a joint motion opposing class certification on February 22, 2008, and various supplements were filed by both parties after that date. On December 19, 2008, the district court issued a preliminary ruling on
certification, indicating its conclusion that several of the class action prerequisites were met and that it was likely to certify a class to adjudicate two issues relating to the emission of H2S in the putative class area, while reserving all remaining issues for subsequent individual adjudications. The district court denied the plaintiffs’ motion to certify a class in reference to the plaintiffs’ medical monitoring claim. The district court requested that the plaintiffs submit a revised class definition consistent with its order, which was submitted by the plaintiffs on January 16, 2009. On January 28, 2009, the defendants filed an objection to the plaintiffs’ revised class definition and requested that the district court deny the plaintiffs’ motion for class certification.
On February 26, 2009, the district court issued an order approving the geographic scope of the plaintiffs’ revised class definition. In its order, the district court denied plaintiffs’ request to include all residents and landowners within the geographic area of the class owning property since October 17, 2006, the date the lawsuit was filed, and limited the class to only current property owners. To date, the district court has not set a date for the final pre-trial conference or a trial date. On March 11, 2009, PennTex Illinois and Rex Operating filed a petition for leave to appeal with the United States Court of Appeals for the Seventh Circuit to appeal the class certification order on an interlocutory basis.
We believe that there is no evidence that any H2S gas emissions from any of our facilities have caused any damage or injury to any person or property, and we intend to vigorously defend against the claims that have been asserted against PennTex Illinois and Rex Operating in this lawsuit. Because this lawsuit is in its initial stages, however, and because it is usually difficult to predict the outcome of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or to estimate the amount or the range of potential loss should the outcome be unfavorable to us.
Pursuant to the terms of a pollution liability policy with Federal Insurance Company, we have insurance coverage for possible damages relating to claims made in this lawsuit for up to $1,000,000. In addition, in accordance with the terms of the pollution liability policy, Federal Insurance Company has agreed to conduct our defense in this lawsuit at the insurer’s expense. Under the terms of a written agreement with us, Federal Insurance Company has agreed to pay a substantial portion of our costs and expenses relating to the defense of this lawsuit, including attorneys’ fees. Under the terms of our agreement, we are required to pay the costs and expenses relating to the defense in excess of the amounts payable by Federal Insurance Company.
21. SUBSEQUENT EVENTS
On January 5, 2009, we entered into a Second Amendment to the Senior Credit Facility (the “Second Amendment”) with KeyBank, as Administrative Agent, and other lenders. The Second Amendment is effective as of December 23, 2008 and amends certain provisions of our senior credit facility entered into on September 28, 2007, as amended by the First Amendment to Credit Facility, entered into on April 14, 2008. (See note 9-Long-Term Debt, for a discussion of the changes made by the Second Amendment)
On January 16, 2009, January 20, 2009 and February 25, 2009, we entered into three derivative commodity transactions. We routinely utilize derivative commodity instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales. A summary of these derivative positions is as follows:
On February 18, 2009, we sold puts and bought back calls of certain of our derivative instruments relating to fiscal year 2011. These derivatives were oil contracts totaling 140,000 barrels, 20,000 barrels per month, from January 1, 2011 to December 31, 2011 and resulted in cash payment to us in the amount of $4.6 million. Our open financial commodity derivative instrument positions at March 11, 2009, consisted of:
22. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.
REX ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
($ and Shares in Thousands Except per Share Data)
(1) Earnings per common share for the third quarter represent the net loss from continuing operations of $361,000 and the gain from discontinued operations of $292,000 for the 2-month period ended September 30, 2007.
ITEM 9.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures to ensure that material information relating to the company is made known to the officers who certify the financial statements and to other members of senior management and the audit committee of our board of directors. As of December 31, 2008, an evaluation was performed under the supervision and with the participation of our management, including the President and Chief Executive Officer (the “CEO”) and the Chief Financial Officer (the “CFO”), of the effectiveness of the design and operation of the our disclosure controls and procedures (as defined in Rules 13a-15(e), and 15d-15(e) under the Securities Exchange Act of 1934). An evaluation was conducted to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our CEO and CFO have concluded that our disclosure controls and procedures were effective as of the date of such evaluation.
Changes in Internal Control over Financial Reporting. No change to our internal control over financial reporting occurred during the year ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange Act of 1934). Management has used the framework set forth in the report entitled Internal Control-Integrated Framework published by the COSO of the Treadway Commission to evaluate the effectiveness of our internal control over financial reporting. Internal control over financial reporting refers to the process designed by, or under the supervision of, our CEO and CFO, and overseen by our board of directors, management and other personnel, 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, and includes those policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with general 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
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Neither internal control over financial reporting nor disclosure controls and procedures can provide absolute assurance of achieving financial reporting objectives because of their inherent limitations. Internal control over financial reporting and disclosure controls are processes that involve human diligence and compliance, and are subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting and disclosure controls also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented, detected or reported on a timely basis by internal control over financial reporting or disclosure controls. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design safeguards for these processes that will reduce, although may not eliminate, these risks.
Management has concluded that our internal controls over financial reporting and our disclosure controls and procedures were effective as of December 31, 2008. Management reviewed the results of their assessment with our Audit Committee. The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by Malin, Bergquist & Company, LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this Annual Report on Form 10-K.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated by reference to such information as set forth in our definitive Proxy Statement (the “2009 Proxy Statement”) for our 2009 annual meeting of stockholders. The 2009 Proxy statement will be filed with the Securities and Exchange Commission (“SEC”) not later than 120 days subsequent to December 31, 2008.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement for the 2009 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement for the 2009 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement for the 2009 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement for the 2009 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements
(a)(2) Financial Statement Schedules
All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.
(a)(3) Exhibits.
* Filed herewith.
+ Indicates management contract or compensation plan or arrangement.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and gas industry terms used in this report:
Basin. A large natural depression on the earth’s surface in which sediments accumulate.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, of crude oil.
Bcf. Billion cubic feet, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.
Bopd. Barrels of oil per day.
Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas.
Development or Developmental well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses, taxes and the royalty burden.
Exploitation. A drilling or other project which may target proved or unproved reserves (such as probable or possible reserves), but generally is expected to have lower risk.
Exploration or Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
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 operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.
Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
Mcfd. One thousand cubic feet of natural gas per day.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.
NYMEX. New York Mercantile Exchange.
PV-10 or present value of estimated future cash flows. An estimate of the present value of the estimated future cash flows from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future cash flows are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future cash flows are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.
Primary recovery. The period of production in which oil and natural gas is produced from its reservoir through the wellbore without enhanced recovery technologies, such as water floods or ASP floods.
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 exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed non-producing reserves or PDNP. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves or PDP. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.
Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, gas and 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 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 addition of production from another interval or formation in an existing wellbore.
Reserve life index. An index calculated by dividing year-end proved reserves by the average production during the past year to estimate the number of years of remaining production.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.
Tertiary recovery. The third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Chemical flooding (including ASP flooding), miscible displacement and thermal flooding are examples of this technique.
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 or gas, regardless of whether or not such acreage contains proved reserves.
Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
Workover. Operations on a producing well to restore or increase production.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: March 11, 2009
REX ENERGY CORPORATION
By:
/s/ BENJAMIN W. HULBURT
Benjamin W. Hulburt
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX
EXHIBIT INDEX
EXHIBIT INDEX
EXHIBIT INDEX
* Filed herewith.
+ Indicates management contract or compensation plan or arrangement.