Rex Energy Corp. 10-K 2012
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
Commission file number: 001-33610
REX ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
476 Rolling Ridge Drive, Suite 300
State College, Pennsylvania 16801
(Address of Principal Executive Offices)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (check one):
Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2011 was $362,511,918. This amount is based on the closing price of the registrants common stock on the NASDAQ Global Market on that date. Shares of common stock beneficially held by executive officers and directors of the registrant are not included in the computation. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
52,902,996 common shares, $.001 par value, were outstanding on March 9, 2012.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants definitive proxy statement for its 2012 Annual Meeting of Stockholders to be held on May 10, 2012, are incorporated by reference herein in Items 10, 11, 12, 13 and 14 of Part III of this report.
REX ENERGY CORPORATION
FOR THE YEAR ENDED DECEMBER 31, 2011
TABLE OF CONTENTS
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
Some of the information, including all of the estimates and assumptions, in this report contain forward-looking statements within the meaning of Sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans, objectives of management for future operations, legal strategies, and legal proceedings, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as may, will, expect, intend, estimate, anticipate, believe, or continue or the negative thereof or variations thereon or similar terminology.
These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:
Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.
SPECIAL NOTE REGARDING THE REGISTRANT
In this report, we refer to certain companiesDouglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New AlbanyIndiana, 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 Partnershipcollectively as the Predecessor Companies. 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, the Company, our, we, us and similar terms refer to Rex Energy Corporation and its subsidiaries together with the Predecessor Companies, after giving effect to the Reorganization Transactions.
Beginning on page 134 of this report, we have included a glossary of oil and natural gas terms used throughout this report.
We are an independent oil and gas company operating in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects and Utica Shale and Upper Devonian Shale exploration activities. In the Illinois Basin, we are focused on the implementation of enhanced oil recovery on our properties as well as conventional oil production. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.
We were incorporated in the state of Delaware on March 8, 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 and DJ Basin properties, unless otherwise noted, which are classified as Discontinued Operations on our Consolidated Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets.
At December 31, 2011, our estimated proved reserves had the following characteristics:
At December 31, 2011, we operated approximately 2,117 wells, which include approximately 517 disposal and injection wells. For the quarter ended December 31, 2011, we produced an average of 49.2 net MMcfe per day, composed of approximately 69.5% natural gas and 30.5% oil and NGLs.
We are one of the largest oil producers in the Illinois Basin, with average net production of 1,900 barrels of oil per day in 2011. 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. During 2010, we commenced chemical injection into our 15-acre Middagh ASP pilot unit. During 2011, we received initial and peak production response from the project and production levels have begun a gradual decline. The successful response from the pilot project resulted in the assignment of 107.6 MBbls of estimated proved developed non-producing reserves to our next planned unit, the Perkins-Smith.
In the Appalachian Basin during 2011, we averaged net production of approximately 27.6 MMcfe per day of natural gas and NGLs. In 2011, we grew our reserves and production in the region primarily through Marcellus Shale drilling projects, while also drilling one successful test well into the Utica Shale and an additional successful test well to the Burkett Shale. As of December 31, 2011, we controlled approximately 129,200 gross (66,400 net) acres, which includes both developed and undeveloped acreage, in areas of Pennsylvania that we believe are prospective for Marcellus Shale exploration and approximately 105,300 gross (69,200 net) acres, which includes both developed and undeveloped acreage, in Pennsylvania and Ohio that we believe are prospective for Utica Shale exploration.
Our total operating revenue for the year ended December 31, 2011 was $114.6 million. Revenue was derived from $111.9 million in oil, natural gas and NGL sales and $2.7 million in other revenue.
For the year ended December 31, 2011, we drilled 64.0 gross (34.2 net) wells, which includes one gross (one net) well drilled in connection with our Lawrence Field ASP Flood Project, and excludes wells drilled in
connection with the DJ Basin for which we have entered a plan to sell and have thus classified the assets as held for sale. Excluding those wells drilled in connection with our ASP project, the wells drilled in 2011 include 36.0 gross (17.1 net) wells that were productive and 27.0 gross (16.1 net) wells that are awaiting completion and are expected to be productive during the first quarter of 2012. The larger inventory of wells awaiting completion is primarily attributable to processing capacity restraints in our Butler County, Pennsylvania area of operations.
The following table sets forth selected data concerning our continuing operations, and our production, estimated proved reserves and undeveloped acreage in our two operating regions for the periods indicated:
Our Competitive Strengths
We believe our strengths provide us with significant competitive advantages and position us to successfully execute our business and growth strategies.
Our Appalachian Basin operations are strategically focused in highly desirable areas. We have a significant presence in the Marcellus Shale, one of the leading unconventional plays in North America, and have secured what we believe to be an advantageous position in the Utica Shale. As of December 31, 2011, we held approximately 66,400 net acres in the Marcellus Shale and approximately 62,400 net acres in the Utica Shale, with approximately 44,100 acres prospective for both formations. Our acreage positions are tightly concentrated, which we believe will enable us to achieve greater efficiencies in our drilling and completion operations than our competitors. (Please see Item 2. PropertiesAppalachian Basin for additional information.)
We have a sizeable inventory of lower-risk development opportunities. As of December 31, 2011, we had an inventory of 22 gross (13.4 net) wells drilled and awaiting completion in our core operations area in the Appalachian Basin, with two gross (1.4) net wells completed and awaiting pipeline infrastructure. Our 2012 drilling program provides for the drilling of an additional 15 wells in locations we believe to be similarly prospective for liquids-rich production. To date, we have achieved a 100% success rate on our drilling program in this area of our operations. We believe that our strong operating history and strategic location of potential drilling sites will continue to provide us with further low-risk development opportunities in this area.
We have attractive growth opportunities in both our Appalachian and Illinois Basin properties. We believe that a significant portion of our Butler County, Pennsylvania acreage is prospective for three producing zones, the Upper Devonian Shale, the Marcellus Shale, and the Utica Shale. In our Illinois Basin properties, we are pursuing tertiary recovery of oil through our 15-acre Middagh Unit ASP pilot and expanded 58-acre Perkins Smith Unit ASP program, and, as of December 31, 2011, have booked proved reserves on these units at 13% of pore volume. We believe these results support our ability to increase oil production through the ASP program. We plan to further expand our ASP efforts and continue our evaluation of potential flood units, with the intention of strategically focusing on those that we believe demonstrate the greatest probability of success. (Please see Item 2. PropertiesAppalachian Basin and Item 2. PropertiesIllinois BasinLawrence Field ASP Flood Project for additional information.)
Market Leader in the Illinois Basin: We are one of the largest oil producers and a market leader in the Illinois Basin. This enables us to realize a current premium over the basin-posted prices on our oil production with a competitive cost structure due to economies of scale. This scale also 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.
Liquids-Rich Exposure: A substantial portion of our acreage holdings are in liquids-rich areas prospective for oil, condensate and NGL production. As of December 31, 2011, our holdings prospective for liquids-rich production accounted for approximately 82.6% of our total net acreage.
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 success rate of approximately 95.7% over the last three years and has helped us improve operations and enhance field recoveries. When excluding operations from the DJ Basin, our success rate increases to 98.2%. We intend to continue 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, including:
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, success in the Marcellus Shale 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 can 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 2011
During 2011, our significant accomplishments included:
Plans for 2012
Our budgeted capital spending for 2012 is approximately $155.3 million. Our 2012 capital budget contemplates the drilling of approximately 15.0 gross (11.0 net) horizontal Marcellus, Utica and Upper Devonian Shale wells in Butler County, Pennsylvania and an additional seven gross (three net) horizontal wells in the joint venture project areas with WPX Energy. In our Carroll County, Ohio operating area, we are expecting to drill three gross (two net) horizontal Utica Shale wells.
Other operational plans for 2012 include the construction and commissioning of a second gas processing facility in Butler County, Pennsylvania, and the expansion of our enhanced oil recovery projects in Lawrence County, Illinois. The following table summarizes our actual 2011 and our budgeted 2012 capital expenditures. 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.
Production, Revenues and Price History
The following table sets forth information regarding oil and gas production and revenues from continuing operations for the last three years:
The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and 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 and services necessary for drilling and completion of wells. Consequently, equipment and services 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.
As of December 31, 2011, we had 204 full-time employees, 123 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, oil and gas leasing and on-site production operation services.
Marketing and Customers
We market nearly all of our oil production from the properties that we operate in the Illinois Basin for both our interest and that of the other working interest owners and royalty owners. For properties that we operate in the Appalachian Basin, our natural gas production is currently marketed by WPX Energy Marketing for our interest and that of the other working interest owners and royalty owners. During the fourth quarter of 2011, we entered into two new natural gas sales agreements. Under the first agreement with BP Energy Company (BP Energy), we have agreed to supply natural gas to BP Energy at certain delivery points in Pennsylvania. During the term of the sales agreement, which is expected to terminate December 31, 2022, we are obligated to provide to BP Energy, and BP Energy is obligated to purchase from us, a minimum monthly volume of natural gas equivalent to 17,500 MMBtu per day from March 1, 2012 to December 31, 2012 and 59,500 MMBtu per day after January 1, 2013. The price for baseload quantities of natural gas is determined by reference to the Dominion Transmission Inc.Appalachia index price published in Platts Inside FERC Gas Market Report for the month of delivery. Under the second agreement with BP Energy, we have agreed to supply natural gas to BP Energy in relation to anticipated Ohio production. During the term of the sales agreement, which is expected to terminate December 31, 2022, we are obligated to provide to BP Energy, and BP Energy is obligated to purchase from us, a minimum monthly volume of natural gas equal to 14,000 MMBtu per day. The price for baseload quantities of natural gas is determined by reference to the Dominion Transmission Inc.Appalachia index price published in Platts Inside FERC Gas Market Report for the month of delivery.
In the Illinois Basin, the majority of our oil is stored at well site tanks and sold to CountryMark Cooperative, LLP (CountryMark), a local refinery, currently at a premium to the basin-posted prices. We receive this premium due to our significant size in the basin relative to other local producers. Purchasers, including CountryMark, purchase our oil at our tank facilities and truck the oil to their refinery facilities. The revenue that we derived from our sales to CountryMark constituted approximately 56.2% of our oil and natural gas revenue from continuing operations for 2011. As such, we are currently significantly dependent on the creditworthiness of CountryMark. We have taken steps to monitor the creditworthiness of CountryMark, including obtaining a letter of credit corresponding to a significant portion of projected monthly revenue. For additional information, see Risk FactorsWe 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, in Item 1A of this report.
On December 30, 2009, we entered into a Master Crude Purchase Agreement (the Master Crude Purchase Agreement) with CountryMark. The agreement was effective as of January 1, 2010. Under the terms of the agreement, we agreed to sell, supply and deliver to CountryMark, and CountryMark agreed to receive and purchase from us, crude oil pursuant to purchase and sale order confirmations that we and CountryMark may enter into from time to time. Under the agreement, until we enter into a confirmation with CountryMark, neither
party is under an obligation to purchase or sell any crude oil. The term of the Master Crude Purchase Agreement provides that the term will automatically be extended for additional one-year terms unless, prior to October 1 of each year, either party gives written notice to the other. We have entered into a confirmation with CountryMark, whereby CountryMark has agreed to purchase substantially all of the crude oil that we produce in 2012 in the Illinois Basin. However, as of December 31, 2011, we were not committed to any delivery levels with CountryMark or any other party. We also have an offload facility at a nearby crude oil pipeline that Marathon Oil Corp operates that has enabled us to diversify our purchasers in the Illinois Basin.
In the Appalachian Basin, our natural gas producing properties are located near existing pipeline systems and processing infrastructure. We transport the majority of our production over our own, or jointly owned, gathering lines to local distribution companies.
Through our joint venture with Keystone Midstream, we have constructed a high pressure gathering system and a cryogenic gas processing plant in Butler County, Pennsylvania. The cryogenic gas processing plant services our wells and third-party wells in areas that produce natural gas with a high BTU content. The cryogenic gas processing plant decreases the BTU level of the gas to appropriate levels for distribution through a standard sales line. The by-products of the cryogenic gas processing plant are natural gas liquids, which are marketed separately. Keystone Midstream is currently in the construction stage for a second cryogenic gas processing plant in Butler County, Pennsylvania.
Prices for oil and natural gas fluctuate widely based on, among other things, supply and demand. Supply and demand are influenced by a number of factors, including weather, foreign policy, industry practices and the U.S. and worldwide economic climate. Oil and natural gas markets have historically been cyclical and volatile in nature as a result of many factors that are beyond our control. There can be no assurance of what price we will be able to sell our oil and natural gas. Prices may be low when our wells are most productive, thereby reducing overall returns.
We enter into derivative transactions with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas prices. For a more detailed discussion, see the information set forth in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Our oil and natural gas exploration, production, and related operations are subject to extensive statutory and regulatory oversight by federal, state, tribal and local authorities. We must, for example, obtain drilling permits, post bonds for drilling, operating, and reclamation, and submit various reports. The following activities are also subject to regulation: the location of wells, the method of drilling completion and operating wells, secondary and enhanced oil recovery projects, notice to surface owners and third parties, the surface development, use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, temporary storage tank operations, air emissions from flaring, compression and access roads, the impoundment of water, the manner and extent of earth disturbances, air emissions, sour gas management, the disposal of fluids used in connection with operations, and the calculation and distribution of royalty payments and production taxes. We must also comply with statutes and regulations addressing conservation matters, including the size of drilling and spacing units, or proration units, the number of wells that may be drilled in an area, the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production. Failure to comply with any of these requirements can result in substantial monetary penalties or lease cancellation. Finally, in the past tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those activities can proceed. Moreover most states impose a production, ad valorem or severance tax with respect to production and sale of oil or natural gas within its jurisdiction.
The increasing regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our production rates. However, these burdens generally do not affect us differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production . Additional proposals or proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commision (FERC), and the courts. Implementation of such could increase the regulatory burden and potential for financial sanctions for non-compliance. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition and results of operations.
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGPA), and the regulations promulgated thereunder by the FERC. In the past, the federal government has regulated the prices at which oil and gas could be sold. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted, removing both price and non-price controls from natural gas sold in first sales no later than January 1, 1993. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.
The FERC regulates interstate natural gas transportation rates and service conditions. Its regulations affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980s, FERC has issued a series of orders, collectively, Order 636, that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other services such pipelines previously performed. One of FERCs purposes in issuing Order 636 was to increase competition within the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.
The price we receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, index such rates to inflation, subject to certain conditions and limitations. We are unable to predict the effect, if any, of these regulations on our intended operations. The regulations may, however, increase transportation costs or reduce well head prices for oil and natural gas liquids.
In August 2005, Congress enacted the Energy Policy Act of 2005 (EPAct 2005). Among other matters, the EPAct 2005 amends the Natural Gas Act (NGA), to make it unlawful for any entity, including otherwise non-jurisdictional producers such as us to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements no misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities
are conducted in connection with gas sales, purchases or transportation subject to FERC jurisdiction which includes the reporting requirements under Order Nos. 704 and 720. It therefore reflects a significant expansion of FERCs enforcement authority. We have not been affected differently than any other producer of natural gas by this act.
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection and the discharge of materials into the environment. These laws and regulations:
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce environmental laws and regulations, and violations may result in fines, injunctions or even criminal penalties. Some states continue to adopt new regulations and permit requirements, which may impede or delay our operations or increase our costs. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and, except for those matters described in Item 3. Legal Proceedings, have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, the trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. Changes in existing environmental laws and regulations or in interpretations of these laws and regulations could have a significant impact on us, as well as the oil and natural gas industry as a whole.
The following is a summary of the existing laws and regulations that could have a material impact on our business operations.
The Resource Conservation and Recovery Act, as amended (RCRA), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration and production of crude oil or natural gas are currently regulated under RCRAs non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition.
The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (CERCLA), and comparable state statutes impose strict liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of hazardous substances found at these sites. This liability may be joint and several and includes liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production, and produced water disposal operations for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been disposed of or released on or under the properties that we own or lease, or on or under other locations, including off-site locations, where these substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.
The Federal Water Pollution Control Act (the Clean Water Act), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The EPA and delegated states have adopted regulations concerning the discharge of storm water runoff. These regulations require covered facilities to obtain individual permits or to seek coverage under a general permit. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the unpermitted discharge of fill material into waters of the United States, including certain wetlands. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Our oil and natural gas exploration and production operations generate produced water as a waste material, which is subject to the disposal requirements of the Clean Water Act, the Safe Drinking Water Act (SDWA), or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, treatment and discharge to the surface or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the Clean Water Act or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the Underground Injection Control program, (UIC), which is a program promulgated under the SDWA. EPA directly administers the UIC in some states and in others it is delegated to the states. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws and regulations.
The Federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. On July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques along with pit flaring of gas not sent to a gathering line. The
standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology, or MACT standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Final action on the proposed rules is expected no later than April 3, 2012. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly reporting, waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For example, recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to warming of the Earths atmosphere. In response to such studies, the U.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions. The ultimate outcome of this legislative initiative remains uncertain. Almost half o fthe states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although it is not possible at this time to predict whether or when the U.S. Congress may act on climate change legislation or how federal legislation may be reconciled with state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an air pollutant under the federal Clean Air Act. On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earths atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Since 2009, the EPA has issued regulations that, among other things, require a reduction in emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 9, 2010 the EPA expanded its greenhouse reporting rule to include onshore petroleum and natural gas production, processing, transmission, storage, and distribution facilities. Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis, with reporting beginning in September 2012 for emissions occurring in 2011.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.
We maintain an internet website under the name www.rexenergy.com. We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the Securities
and Exchange Commission (SEC). Our Corporate Governance Policy, the charters of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee, and the Code of Ethics for directors, officers, employees and financial officers are also available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 476 Rolling Ridge Drive, Suite 300, State College, PA 16801.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SECs Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Rex Energy Corporation, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
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
Volatility in oil, NGL 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 prices we receive for our oil, NGL 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:
Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, NGLs 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. A sustained decline in oil, NGL 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.
Drilling for and producing oil, NGLs 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, NGL 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, NGL 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. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities
and present value of our reserves. Please see 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:
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
Prospects that we decide to drill may not yield oil, NGLs 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, NGLs 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, NGLs or natural gas will be present or, if present, whether oil, NGLs 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.
Our estimated proved 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 proved reserve 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, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil, NGL 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 prospectus supplement. In addition, we may adjust estimates of estimated proved reserves to reflect production history, results of exploration and development, prevailing oil, NGL and natural gas prices and other factors, many of which are beyond our control.
The present value of future net cash flows from our estimated 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 estimated 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:
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 estimated 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.
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. For 2012, we have budgeted approximately $155.3 million for capital expenditures for development and exploration activities in the Appalachian and Illinois Basins. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations, public stock offerings, sales of non-core assets and joint venture agreements. We intend to finance our future
capital expenditures with proceeds from bank borrowings, the sale of debt or equity securities, asset sales, cash flow from operations and current and new financing arrangements, such as joint ventures. Our cash flow from operations and access to capital is subject to a number of variables, including:
If our revenues decrease as a result of lower oil, NGL 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 senior credit facility and our second lien credit facility each contain 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.
Our indebtedness could adversely affect our financial condition and our ability to operate our business.
As of December 31, 2011, outstanding borrowings under our senior credit facility and our second lien credit facility totaled $225.0 million. We will incur additional debt from time to time, and such borrowings may be substantial. Our debt could have material adverse consequences to us, including the following:
In addition, the agreements governing our senior credit facility and second lien term loan contain a number of significant covenants that place limitations on our activities and operations, including those relating to (i) creation of liens; (ii) hedging activities; (iii) mergers, acquisitions, asset sales and dispositions; (iv) payment of dividends; and (v) incurrence of additional indebtedness. Our credit agreements also require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary or desirable corporate activities.
The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 53% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2011. Development of these reserves may take longer and require higher levels of capital
expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our estimated proved reserves as unproved reserves.
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 are 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.
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 between three and four million gallons of water per well in our Marcellus Shale well completion operations. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our operations. Moreover, the adoption and implementation of new environmental regulations could result in restrictions on our ability to conduct certain operations such as hydraulic fracturing or the imposition of new requirements pertaining to the management and disposal of wastes generated by our operations, 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 adversely affect our financial condition and results of operations.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and drilling and completion 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, services and supplies. In addition, larger producers may be more likely to secure access to such equipment and services 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.
Federal, state and local regulation of hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In
addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.
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 our oil, NGLs, and natural gas and/or receive market prices for our oil, NGLs and natural gas may be adversely affected by pipeline and gathering system capacity constraints.
Market conditions or the unavailability of satisfactory oil, NGL and natural gas transportation arrangements may hinder our access to oil, NGL and natural gas markets or delay our production. The availability of a ready market for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs 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, NGLs or natural gas may have several adverse effects, 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 and other areas of the Appalachian Basin 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 these areas may not occur. 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, NGL 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.
Enhanced Oil Recovery (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, or 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 resources associated with our ASP project in the Lawrence Field are not considered estimated proved reserves. Our ability to achieve commercial production and recognize estimated 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 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 operators breach of the applicable agreements or an operators 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 operators:
All of the value of our production and reserves is concentrated in the Illinois Basin and Appalachian 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, 2011, approximately 29% of our net production came from the Illinois Basin area and 71% came from the Appalachian Basin. As of December 31, 2011, approximately 13.4% of our estimated proved reserves were located in the fields that comprise the Illinois Basin and 86.6% of our estimated proved reserves were a result of our Appalachian Basin operations. If mechanical problems, weather conditions or other events were to curtail a substantial portion of the production in one or both of these regions, our cash flow would 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.
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, NGLs 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.
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.
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.
For the year ended December 31, 2011, we incurred impairment charges from continuing operations of approximately $14.6 million. Approximately $11.6 million of the estimated pre-tax impairment expense for the fourth quarter of 2011 is related to the impairment of shallow conventional natural gas properties in the Appalachian Basin as a result of lower current and projected natural gas prices.
Additional write downs could occur if oil and gas prices 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.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil, NGL 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.
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, NGLs and natural gas, including the possibility of:
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.
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, NGLs 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:
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.
We must obtain governmental permits and approvals for our drilling and mid-stream operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
Our operations expose us to substantial costs and liabilities with respect to environmental matters.
Our oil, NGL 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 the issuance of injunctions restricting or prohibiting certain activities. 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 whether 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.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.
In December 2009, the EPA published its findings that emissions of greenhouse gases (GHGs) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earths atmosphere and other climatic conditions. Based on these findings, in
2010 the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration, or PSD, construction and Title V operating permit programs, pursuant to which these permit programs have been tailored to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, in November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. We are evaluating whether GHG emissions from our operations are subject to the GHG emissions reporting rule and expect to be able to comply with any applicable reporting obligations. Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the oil, natural gas and NGLs we produce. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earths atmosphere may produce climate change that could have significant physical effect, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our assets and operations.
The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to use derivative instruments, particularly swaps, to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, was enacted in 2010. The Act provides for new statutory and regulatory requirements for derivative transactions, including certain oil and gas hedging transactions involving swaps. In particular, the Act includes a requirement that certain hedging transactions involving swaps be cleared and exchange-traded and a requirement to post cash collateral for non-cleared swap transactions, although, at this time, it is unclear which transactions will ultimately be required to be cleared and exchange-traded or which counterparties will be required to post cash collateral with respect to non-cleared swap transactions. The Act provides for a potential exception from the clearing and exchange-trading requirement for hedging transactions by commercial end-users, a category of non-financial entities in which we may be included. While the Commodity Futures Trading Commission, or CFTC, and other federal agencies have adopted, and continue to adopt, numerous regulations pursuant to the Act, many of the key concepts and defined terms under the Act have not yet been delineated by rules and regulations to be adopted by the CFTC and other applicable regulatory agencies. As a consequence, it is difficult to predict the aggregate effect the Act and the regulations promulgated thereunder may have on our hedging activities. Whether we are required to submit our swap transactions for clearing or post cash collateral with respect to such transaction will depend on the final rules and definitions adopted by the CFTC. If we are subject to such requirements, significant liquidity issues could result by reducing our ability to use cash posted as collateral for investment or other corporate purposes. A requirement to post cash collateral could also limit our ability to execute strategic hedges, which would result in increased commodity price uncertainty and volatility in our future cash flows. The Act and related regulations will also require us to comply with certain futures and swaps position limits and new recordkeeping and reporting requirements, and may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and related regulations could also materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Enactment of a Pennsylvania severance tax and impact fees 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.
While Pennsylvania has historically not imposed a severance tax (relating to the extraction of natural gas), with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, various legislation has been proposed since 2008. In February 2012, Pennsylvania implemented an impact fee. This new law imposes an impact fee on all unconventional wells drilled in the Commonwealth of Pennsylvania in counties that elect to impose the fee. The fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. Based upon natural gas prices for 2011, operators will pay $50,000 per unconventional horizontal well. Unconventional vertical wells will pay a fee equal to twenty percent of the horizontal well fee and the impact fee will not apply to any unconventional vertical well that produces less than 90mcf per day. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded and the fee will continue for 15 years for a horizontal well and 10 years for a vertical well.
Future economic conditions in the U.S. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.
The U.S. and other world economies are still recovering from a recession which began in 2008 and extended into 2009. While economic growth has resumed, the timing and extent of an economic recovery are uncertain. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in previous years. Unemployment rates remain high and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand growth for our crude oil, NGL and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.
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. We received net payments of $6.2 million in relation to our commodity derivative instruments for the year ended December 31, 2011.
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 and second lien credit facility 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.
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, approximately 96%, from sales to a relatively small number of purchasers. If we were unable to continue to sell our oil, NGLs, or natural gas to these key customers, or to offset any reduction in sales to these customers by additional sales to our other customers, it 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.
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.
Our future acquisitions may yield revenue or production that varies significantly from our projections.
In pursuing potential acquisition of oil and natural gas properties, we will assess the potential 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.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and natural gas exploration and production activities of certain U.S. federal income tax incentives and deductions currently available to such companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such changes may apply retroactively. Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.
The outcome of litigation in which we have been named as a defendant is unpredictable and an adverse decision in any such matter could have a material adverse effect on our financial position or results of operations.
We are defendants in a number of litigation matters and are subject to various other claims, demands and investigations. These matters may divert financial and management resources that would otherwise be used to benefit our operations. No assurances can be given that the results of these matters will be favorable to us. An adverse resolution or outcome of any of these lawsuits, claims, demands or investigations could have a negative impact on our financial condition, results of operations and liquidity.
Risks Related to Our Common Stock
We may issue additional common stock in the future, which would dilute our existing stockholders.
In the future we may issue our previously authorized and unissued securities, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our amended and restated certificate of incorporation 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. As of March 9, 2012, there were 52,902,996 shares of our common stock issued and outstanding and there were no shares of our preferred stock issued and outstanding.
We have an effective shelf registration statement from which additional shares of our common stock and other securities can be issued. We may also issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with future public offerings, the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. Future issuances of our common stock, or the perception that such issuances could occur, could have a material adverse effect on the price of our common stock.
Our amended and restated certificate of incorporation, amended and restated 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, who collectively beneficially own approximately 21% of the outstanding shares of our common stock as of March 9, 2012.
Provisions in our amended and restated certificate of incorporation and amended and restated bylaws could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:
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.
As of March 9, 2012, our board of directors, including Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 21% 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 stockholder approval, 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.
The provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law, and the concentrated ownership of our common stock by our Chairman and other 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 and our second lien 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.
We are able to issue shares of preferred stock with greater rights than our common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights, or voting rights. If we issue preferred stock, it may adversely affect the market price of our common stock.
Substantial sales of our common stock could cause our stock price to decline.
If our stockholders sell a substantial number of shares of our common stock, or the public market perceives that our stockholders might sell shares of our common stock, the market price of our common stock could decline significantly. We cannot predict the effect that future sales of our common stock or other equity-related securities by our stockholders would have on the market price of our common stock.
As of the date of this filing, we have no unresolved comments from the staff of the SEC.
The table below summarizes certain data for our core operating areas for the year ended December 31, 2011:
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.
In the Illinois Basin, we own an interest in 1,842 wells, which includes 506 disposal and injection wells. We have approximately 61,700 gross (35,000 net) acres owned and under lease.
Total estimated proved reserves, and proved developed reserves, in the Illinois Basin increased approximately 0.2 Bcfe, or 0.5%, to approximately 49.1 Bcfe at December 31, 2011 when compared to year-end 2010, which was primarily a result of the addition of estimated proved reserves from our ASP project and increased oil prices, partially offset by natural production declines. Annual production increased 0.3% from 2010. Capital expenditures in 2011 for drilling and facility improvements in the region were approximately $13.3 million, which funded the drilling of six gross (three net) wells, of which four gross (two net) was awaiting completion as of December 31, 2011. These expenditures also covered work performed in the basin designed to optimize our secondary waterflood operations whereby we stabilized declining production. Capital expenditures for drilling and facilities development for the Lawrence Field ASP Flood Project totaled approximately $4.0 million.
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 considered an Enhanced Oil Recovery (EOR) project, which refers to recovery of oil that is not producible by primary or secondary recovery methods.
We currently own and operate 21.2 square miles (approximately 13,500 net acres) of the Lawrence 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. While we believe the results of these projects 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 prior EOR projects, 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, a surfactant and a polymer. The alkali and surfactant combination acts like a soap and washes residual oil from the reservoir mainly by reducing interfacial tension between the oil and the water. The polymer is added to improve sweep displacement efficiency by pushing the washed oil through the rock pores of the reservoir.
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 Resources Illinois, Inc., one of our Predecessor Companies, 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. However, there can be no assurance that our Lawrence Field ASP Flood Project will achieve similar results to those conducted in the study.
During 2008 and 2009, we completed two four acre pilot tests, one each in the Bridgeport and Cypress sandstones. Both of the pilots demonstrated a response to the chemical injection, 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%. During 2010 we commenced chemical injection into our 15-acre Middagh ASP pilot unit and received initial and peak response during 2011, with oil cuts increasing from 1% to approximately 12%, with several wells peaking at an oil cut of 17%. Production has since began its gradual decline, however the successful response from this project resulted in the assignment of 107.6 MBbls of net proved developed non-producing reserves as of December 31, 2011. We are continuing to move forward with ASP expansion with the 58-acre Perkins Smith project area. ASP injection into the Perkins Smith is expected to begin in the second quarter of 2012, with initial production response expected early in 2013. Development and testing work is underway to initiate the potentially high impact 351-acre Delta Unit ASP flood. We are currently evaluating various development and spacing scenarios to determine the optimal pattern performance in this project.
We have identified, thus far, 27 potential separate flood units (15 Bridgeport/12 Cypress). Depending on the size of each flood unit, it is anticipated that initial response time from the chemical injection date will be approximately 10 to 12 months and the time to peak response will be approximately 24 to 30 months.
As of December 31, 2011, we owned an interest in approximately 512 producing natural gas wells in the Appalachian Basin, located predominantly in Pennsylvania. In addition to our producing wells in the basin, we own 89.0 gross Marcellus Shale PUD drilling locations and 1.0 gross Burkett Shale PUD drilling location with total reserves of 192.9 Bcfe, and three locations,
including one each in the Marcellus, Utica, and Burkett Shale plays, with proved developed non-producing reserves totaling 8.3 Bcfe. At December 31, 2011, we had approximately 162,200 gross (93,900 net) acres in the Appalachian Basin under lease, of which 104,100 gross (69,400 net) acres were undeveloped.
Reserves at December 31, 2011 increased 164.3 Bcfe, or 107.5%, from 2010 due primarily to our successful Marcellus Shale exploration activities. Annual production increased 210.2% over 2010.
Capital expenditures in 2011 for drilling and facility development totaled $187.3 million, which funded the drilling of 57.0 gross (30.2 net) wells. During the year, we placed into service 51.0 gross (25.9 gross) wells and had an inventory of 25.0 gross (15.2 net) wells awaiting completion or a pipeline connection. Our plans for 2012 have allocated approximately $133.7 million in capital expenditures to our Marcellus, Utica and Burkett Shale project areas.
As of December 31, 2011, we had interests in approximately 129,200 gross (66,400 net) Marcellus Shale prospective acres in areas of Pennsylvania and we continue to expand our position by strategically filling in key pieces of acreage to complete drilling units.
In June of 2009, we entered into a Participation and Exploration Agreement (the Williams PEA) with WPX Energy San Juan, LLC (formerly known as Williams Production Company, LLC) and Williams Production Appalachia, LLC, whom we collectively refer to as Williams. Under the terms and conditions of the Williams PEA, Williams acquired, through a drill-to-earn structure, 50% of our working interest in certain oil and gas leases covering approximately 44,000 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the Project Area). The Williams PEA effectively provided that, for Williams to earn its 50% interest in the Project Area, Williams had to bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams had invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams 50% share of the wells). Once Williams completed its carry obligation and acquired 50% of our working interest in the leases within the Project Area, the parties would become obligated to share all costs of the joint venture operations with an area of mutual interest (including the Project Area) in accordance with their participating interests, which were expected to be on a 50/50 basis prior to our Sumitomo joint venture transaction (described below). Williams met its drilling carry obligation during the fourth quarter of 2010.
On September 30, 2010, we entered into a joint venture transaction with Summit Discovery Resources II, LLC and Sumitomo Corporation, whom we collectively refer to herein as Sumitomo. In Butler, Beaver and Lawrence Counties, Pennsylvania we sold a 15% non-operated interest in approximately 41,000 net acres for approximately $30.6 million in cash at closing and $30.6 million in the form of a drilling carry of 80% of our drilling and completion costs in the area. Pursuant to the Participation and Exploration Agreement (the Sumitomo PEA), Sumitomo agreed to pay all costs to lease approximately 9,000 acres in the Butler County Area of Mutual Interest (AMI) (the Phase I Leasing), and was obligated to pay to us a leasing management fee of $1,000 per net acre during the Phase I Leasing. Under the Sumitomo PEA, upon the conclusion of Phase I Leasing, we were required to cross assign interests in the leases with Sumitomo to provide uniformity of interest in each lease in the Butler County AMI. The Phase I Leasing Project is substantially complete, with the final ownership percentages in the Butler County AMI being approximately 70% to us and 30% to Sumitomo. In addition to the sale of undeveloped acreage, we also sold to Sumitomo 30% of our interests in 20 Marcellus Shale wells within the Butler County AMI and 30% of our interest in Keystone Midstream Services, LLC.
In our Marcellus Shale joint venture Project Area with Williams, which is discussed above, we sold to Sumitomo 20% of our interests in 21,000 net acres for approximately $19.0 million in cash at closing and $19.0 million in the form of a drilling carry of 80% of our drilling and completion costs in the Project Area. In addition,
we sold 20% of our interests in 19 Marcellus Shale wells located in the Williams joint venture areas and 20% of our interest in RW Gathering, LLC. The resulting working interest ownership is 50% Williams, 40% Rex Energy and 10% Sumitomo.
In addition to the areas above, we sold to Sumitomo 50% of our interests in approximately 4,500 net acres in Fayette and Centre Counties, Pennsylvania for $9.2 million in cash at closing and $9.2 million in the form of a drilling carry of 80% of our drilling and completion costs. Pursuant to the Sumitomo PEA, the drilling carry for these areas was able to be applied, at our discretion, to drilling and completion costs attributable to either the Butler County or Williams Project Areas.
At closing, we received approximately $99.5 million in cash, which included a reimbursement for leasing expenses incurred subsequent to the effective date of September 1, 2010, in the amount of $7.6 million. Additionally, the cash payment included a reimbursement for drilling related expenses incurred subsequent to the effective date in the amount of approximately $7.5 million, which was applied against the drilling carry. Sumitomo met its drilling carry obligation during the first quarter of 2011.
During 2011, we drilled our first Utica Shale test well for which we successfully booked proved developed non-producing reserves, as the well was awaiting pipeline construction at the end of the year. We estimate that much of our acreage in Butler County, Pennsylvania is prospective for dry gas Utica Shale production as well as acreage in some other non-core areas of Pennsylvania. As of December 31, 2011, we estimate Utica Shale acreage holdings in Pennsylvania of approximately 92,300 gross (56,400 net).
We expanded our Utica Shale exploration activities into Ohio during 2011, acquiring approximately 13,000 gross (12,900 net) acres, not including 2,000 gross (2,000 net) acres that are pending the clearance of title, which we believe to be prospective for liquids-rich production. We plan to spud the first test well in Ohio during the second quarter of 2012.
During 2011, we drilled our first Burkett Shale test well for which we successfully booked proved developed non-producing reserves, as the well was awaiting pipeline connection at the end of the year. The Burkett Shale is one of the shales that lies within the Upper Devonian formation. We estimate that much of our acreage in Butler County, Pennsylvania is prospective for wet gas Burkett Shale production. As of December 31, 2011, we estimate Burkett Shale acreage holdings of approximately 67,200 gross (44,800 net).
Estimated Proved Reserves
For estimated proved reserves as of December 31, 2011, proved locations were identified, assessed and justified using the evaluation methods of performance analysis, volumetric analysis and analogy. In addition, reliable technologies were used to support a select number of undeveloped locations in the Marcellus Shale Region. Within the Marcellus Shale Region, we used both public and proprietary geologic data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, micro-seismic analysis, open hole log information and petro-physical analysis of the log data, mud logs, log cross-sections, gas sample analysis, drill cutting samples, measurements of total organic content, thermal maturity and statistical analysis. In our development area, these data demonstrated consistent and continuous reservoir characteristics.
The following table sets forth our estimated proved reserves as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K:
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 1ARisk FactorsOur 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 Financial Statements for the year ended December 31, 2011 in conjunction with the following reserve estimates.
The following table sets forth our estimated proved reserves at the end of each of the past three years:
Proved Undeveloped Reserves (PUDs)
As of December 31, 2011, our PUD reserves totaled 4.9 MMBOE of NGLs and 163.4 Bcf of natural gas, for a total of 192.9 Bcfe. All of our PUDs at year-end 2011 were associated with the Appalachian Basin. All of these projects will have PUDs convert from undeveloped to developed as these projects begin production and/or production facilities are expanded or upgraded. Changes in PUDs that occurred during the year were due to:
Costs incurred relating to the development of 16.0 gross (9.5 net) PUDs to proved developed were approximately $20.2 million in 2011. Estimated future development costs relating to the development of our 90.0 gross (54.1 net) PUDs are projected to be approximately $44.9 million in 2012, $52.1 million in 2013, $104.7 million in 2014 and $46.1 million in 2015.
All PUD drilling locations are scheduled to be drilled prior to the end of 2015, including approximately 13.3% of the total in 2012. Initial production from these PUDs is expected to begin between 2012 and 2016. We do not have PUDs associated with reserves that have been booked for longer than five years. Approximately 33.0 gross (18.6 net) PUDs were booked based on reliable technology.
The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2011:
Netherland, Sewell & Associates, Inc. (NSAI), an independent petroleum engineering firm, evaluated our reserves on a consolidated basis as of December 31, 2011. At December 31, 2011, these consultants collectively
reviewed all of our estimated proved reserves. A copy of the summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our estimated proved reserves estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include documented process workflows, the verification of input data used by NSAI, as well as extensive management review and approval.
All of our reserve estimates are reviewed and approved by our Director, Reservoir Engineering and our President and Chief Operating Officer. Our Director, Reservoir Engineering holds a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin with more than seven years of experience in preparing reserve reports under the guidelines of the SEC with Cano Petroleum and with us. Our President and Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming and an M.B.A. from Pepperdine University, with approximately 25 years of experience working for companies such as Cano Petroleum, Pioneer Natural Resources and Union Pacific Resources.
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, 2011:
Substantially all of the undeveloped leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed, we have commenced the necessary operations required by the terms of the lease, or have obtained actual production from acreage subject to the lease, 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:
The following table summarizes our drilling activity for continuing operations 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 four 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. A more comprehensive mineral title opinion review, a topographic evaluation and infrastructure 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:
The information set forth in Note 24, Litigation, in the notes to our Consolidated Financial Statements included in Item 8 of Part II of this report is incorporated herein by reference.
We completed the initial public offering of our common stock in July 2007. Since that time, our common stock has been quoted on the NASDAQ Global Market under the symbol REXX. Before then, there was no public market for our common stock. As of March 9, 2012, there were approximately 88 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.
The closing price of our common stock on March 9, 2012 was $10.71.
We have not paid cash dividends on our common stock since our inception in March 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 generally prohibit the payment of 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.
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, 2011, 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.
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 financial data has been prepared for Rex Energy Corporation for the years ended December 31, 2011, 2010, 2009 and 2008. The historical combined financial data has been prepared for the Predecessor Companies for the year ended December 31, 2007. 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 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 of this report, Managements Discussion and Analysis of Financial Condition and Results of Operations, and our Consolidated Financial Statements and related notes as of December 31, 2011 and 2010 and for each of the years ended December 31, 2011, 2010 and 2009, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.
The following tables include the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Non-GAAP Financial Measures section.
Summary Operating and Reserve Data
The following table summarizes our operating and reserve data as of and for each of the periods indicated for continuing operations. The table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Non-GAAP Financial Measures below.
Non-GAAP Financial Measures
We include in this report our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.
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 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:
EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance, nor used as an exclusive measure of cash flow, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our statements of cash flows.
We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and we believe this measure is commonly reported and widely used by investors as an indicator of a companys operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed our EBITDAX to permit a more complete
comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for managements discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.
We believe EBITDAX assists our lenders and investors in comparing a companys performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.
To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.
The following table presents a reconciliation of our net income to our EBITDAX for each of the periods presented:
The following table shows the reconciliation of PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 represents our estimate of the present value, discounted at 10% per annum, of estimated future cash flows of our estimated proved reserves before income tax and asset retirement obligations. Our estimated future cash flows as of December 31, 2009, 2010 and 2011 were determined by using reserve quantities of estimated proved reserves and the periods in which they are expected to be developed and produced based on the prevailing economic conditions. The estimated future production for the years ended December 31, 2009, 2010 and 2011, was priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December, without escalation, using $57.65 per Bbl, $76.03 per Bbl and $92.45 per Bbl of oil, respectively, and $3.866 per MMBtu, $ 4.567 per MMBtu and $4.545 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. NGLs were priced at $57.65 per Bbl, $31.71 per Bbl and $46.34 per Bbl for the years ended December 31, 2009, 2010 and 2011, respectively. Management believes that 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. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
The following discussion and analysis should be read in conjunction with Item 6. Selected Financial Data and the Consolidated 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 Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects and Utica Shale exploration. In the Illinois Basin, in addition to our developmental conventional oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.
We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois, Butler, Pennsylvania, Seven Fields, Pennsylvania and Carrolton, Ohio.
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.
During 2011, we increased our proved reserves base by approximately 81.6%, from 201.7 Bcfe at December 31, 2010. The primary contributing factor to this increase was our continued drilling success in the Appalachian Basin, where we drilled 51.0 gross (25.9 net) wells which also resulted in an increase in production of 92.4%. Amidst our successful drilling endeavors, we successfully drilled two successful test wells, one to the Utica Shale and one to the Burkett Shale, solidifying our belief that there are multiple producing zones underlying our acreage in Butler County, Pennsylvania. We continued to increase our acreage position in the Appalachian Basin during 2011, ending the year with approximately 162,200 gross (93,900 net) acres under leasehold, which includes approximately 15,000 gross acres in Ohio that we believe to be prospective for the liquids-rich portion of the Utica Shale. As of December 31, 2011, our acreage holdings prospective for liquids-rich production accounted for approximately 82.6% of our total net acreage. Through our acreage holdings and successful drilling operations we have been able to expand our available drilling inventory, which now includes 192.9 Bcfe in proved undeveloped reserves covering 90.0 gross proved undeveloped drilling locations. To prepare for our future growth, we have entered into various gathering, processing and sales agreements to ensure market capacity for our projected production.
In 2010, we entered into a joint venture agreement with Sumitomo. In accordance with the agreement, we sold a 15% non-operated interest in our Butler County, Pennsylvania project area and Sumitomo also agreed to lease an additional 9,000 acres in this project area. The leasing arrangement was concluded during 2011; consequently, the ownership percentages in the project area are approximately 70% to us and 30% to Sumitomo. In addition to our Butler County, Pennsylvania project area, we also sold a 20% non-operated interest in our joint
venture area with Williams (discussed below) and a 50% non-operated interest in undeveloped acreage in Fayette and Centre Counties, Pennsylvania. At closing, we received approximately $99.5 million in cash, which included a reimbursement for leasing expenses incurred subsequent to the effective date of September 1, 2010, in the amount of $7.6 million, and a reimbursement for drilling related expenses incurred subsequent to the effective date in the amount of approximately $7.5 million. As a part of the joint venture agreement, Sumitomo agreed to pay 80% of our net drilling and completion expenses up to approximately $58.8 million. For additional information on the transaction with Sumitomo, see Note 3, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.
In 2009, we entered into a joint venture agreement with Williams. In accordance with the agreement, we sold a 50% working interest in certain oil and gas leases in Centre, Clearfield and Westmoreland Counties, Pennsylvania through a drill-to-earn structure. For Williams to earn its 50% interest they were required to bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled until such time Williams had invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams 50% share of the wells). As of December 31, 2010, Williams had completed its carry obligation and acquired their 50% working interest. Subsequent to the joint venture agreement with Sumitomo, the ownership percentages are approximately 50% to Williams, 40% to us and 10% to Sumitomo. For additional information on the transaction with Williams, see Note 3, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.
Source of Our Revenue
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:
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 in 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.
Principal Components of Our Cost Structure
Our operating and other expenses consist of the following:
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX (a non-GAAP measure), lease operating expenses per Mcf equivalent (Mcfe), growth in our proved reserve base, and general and administrative expenses per Mcfe. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2011, 2010 and 2009.
EBITDAX, a non-GAAP measure, 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 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:
For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Non-GAAP Financial Measures.
Production Cost per Mcfe
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, gathering, processing, fuel and the wages of our field personnel. Our production costs per Mcfe 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. Our production cost per Mcfe produced in 2011 was $2.33 as compared to $3.34 in 2010 and $3.77 in 2009. As we continue to develop our non-proved properties, such as the Marcellus Shale, which have a lower operating cost, we believe this metric will continue to decrease on a per unit basis.
Growth in our Proved Reserve Base
We measure our ability to grow our estimated proved reserves over the amount of our total annual production. As we produce oil and gas attributable to our estimated proved reserves, our estimated proved reserves decrease each year by that amount of production. We attempt to replace these produced estimated proved reserves each year through the addition of new estimated proved reserves through our drilling and other property improvement projects and through acquisitions. Our estimated proved reserves have fluctuated since 2009, from 125.2 Bcfe at year end 2009 to 201.7 Bcfe at year end 2010 to 366.2 Bcfe at year end 2011. Our reserve replacement ratio for year end 2009 was approximately 410% based on total production for the year of 5.9 Bcfe and extensions, discoveries and other additions of 24.1 Bcfe. Our reserve replacement ratio for year end 2010 was approximately 1,559% based on total production for the year of 7.3 Bcfe, and extensions, discoveries and other additions of 98.2 Bcfe. Our reserve replacement ratio for year end 2011 was approximately 1,096% based on total production for the year of 14.2 Bcfe, and extensions, discoveries and other additions of 178.7 Bcfe.
Our estimated proved reserve base increased in 2011 when compared to 2010 predominately due to our successful drilling and exploration programs in the Marcellus Shale and the increase in oil prices used for the reserves determination. As of December 31, 2010, we removed all proved undeveloped locations related to our conventional drilling opportunities in the Illinois and Appalachian Basins from our proved reserve totals, which
is in compliance with SEC rules requiring a high degree of confidence that the quantities related to proved undeveloped reserves will be recovered and they are scheduled to be drilled within the next five years. For 2011, our proved reserve base in the Marcellus Shale increased by approximately 112.8%, while our estimated proved reserves in the Illinois Basin increased by 0.5%.
General and Administrative Expenses per Mcfe
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 production because these expenses have a direct impact on our profitability. In 2011 our general and administrative expenses per Mcfe produced decreased to $1.66 from $2.32 in 2010 and from $2.70 in 2009. As we continue to develop our non-proved properties, we believe this metric will continue to decrease on a per unit basis.
Results of Continuing Operations
Operating revenue increased 66.7% for 2011 over 2010. This increase is primarily due to increased oil and gas production in each of our operating regions and higher oil and NGL prices, which were partially offset by lower natural gas prices. For 2011, total production increased 92.4% to 14,220 MMcfe from 7,391 MMcfe in 2010 due to the continued success of our drilling programs, primarily in the Marcellus Shale.
Operating expenses increased $45.3 million in 2011, or 75.6%, as compared to 2010. Operating expenses are primarily composed of production expenses, general and administrative expenses, gain (loss) on disposal of assets, exploration expenses, impairment of oil and gas properties and depreciation, depletion, amortization and accretion expenses (DD&A). The increases in operating expense were primarily due to the growth of our operations, particularly in Butler County, Pennsylvania where we are required to process our gas prior to entry into the sales line. Also contributing to the increase were impairment expenses, which were approximately $5.8 million higher than in 2010 primarily due to the write-down of our conventional natural gas properties in the Appalachian Basin. Approximately $16.4 million of the increase was due to the gain on sale recognized as a result of the Sumitomo transaction in 2010.
Comparison of the Year Ended December 31, 2011 to the Year Ended December 31, 2010
Oil and gas revenue for the years ended December 31, 2011 and 2010 is summarized in the following table:
Average realized price received for oil and gas during 2011 was $8.30 per Mcfe, a decrease of 9.7%, or $0.90 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2011 increased 28.5% or $20.05 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 15.4%, or $0.92 per Mcf, from 2010. Our derivative activities effectively increased net realized prices by $0.44 per Mcfe in 2011 and $0.11 per Mcfe in 2010.
Production volume for 2011 increased 92.4% from 2010 primarily due to the success of our Marcellus Shale horizontal drilling plan in the Appalachian Basin, where production increased approximately 210.2%, or 6.8 Bcfe. Our production for 2011 averaged approximately 38,959 Mcfe per day of which 29.3% was attributable to the Illinois Basin and 70.7% to the Appalachian Basin.
Statements of Operations for the years ended December 31, 2011 and 2010 are as follows:
Other Revenue for 2011 of approximately $2.7 million increased $1.2 million, or 77.2%, from 2010. During 2010, we entered into a joint venture that specializes in the sourcing and transportation of water in the
Marcellus Shale regions of the Appalachian Basin. Revenues earned by this joint venture, Water Solutions Holdings, LLC (Water Solutions), of which we own 80%, have been classified as Other Revenue and did not exist prior to 2010.
Production and Lease Operating Expense increased approximately $8.5 million, or 34.3%, in 2011 from 2010. The increase is primarily due to processing and gathering fees incurred in our Butler County, Pennsylvania operating region. We produce wet gas in this region, which requires processing before it can be sold. As such, we jointly constructed a cryogenic gas processing plant for which we pay fees to have our gas transported and processed before sale. We incurred approximately $4.6 million in expenses related to processing and gathering during 2011 and approximately $0.3 million in 2010. Also contributing to our increased expenses was the growth of our Appalachian Basin operations, where we placed into service 51.0 gross (25.9 net) wells in 2011.
General and Administrative Expense of approximately $23.6 million for 2011 increased approximately $6.5 million, or 37.9%, from 2010. The increase in general and administrative costs is attributable to legal expenses, severance wages and an overall increase in headcount. We incurred $2.5 million in legal costs associated with the settlement of our leasing lawsuit in Westmoreland County, Pennsylvania. During 2011, we entered into separation agreements with several employees for which we incurred approximately $1.0 million in severance costs. The remainder of the increase during 2011 is primarily attributable to our continued efforts to hire and retain high quality personnel. We have incurred higher recruiting, wages and benefits costs to achieve this goal, which includes approximately $1.6 million in non-cash compensation in 2011 as compared to $0.9 million in 2010.
(Gain) Loss on Disposal of Assets for 2011 was a loss of approximately $0.5 million as compared to a gain of $16.4 million for 2010. From time to time, we 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.
Impairment Expense increased to $14.6 million in 2011 from $8.9 million, or 64.0%, in 2010. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. During 2011 we incurred approximately $11.6 million of impairment expense related to conventional shallow natural gas properties in the Appalachian Basin due to their estimated fair value being less than their carrying value as of December 31, 2011. These wells are characterized as older wells that produce at much lower rates than the unconventional shale plays. While they are less capital intensive and have lower operating costs, their lower production levels combined with lower commodity pricing make them susceptible to impairment write downs. The remainder of our impairment in 2011 was primarily due to the expiration of leased acreage. During 2010, impairment expense was primarily related to two test wells in Clearfield County, Pennsylvania. We determined that the carrying value of these two test wells, which were in various stages of drilling and completion, was not recoverable due to a lack of a sales outlet and no then-current plans by us to complete the wells for commercial production. We periodically evaluate the capitalized costs associated with properties that are outside of our current scope of operations as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.
Exploration Expense of oil and gas properties for 2011 decreased approximately $0.1 million from $2.6 million in 2010. Exploration costs incurred by us during 2011 and 2010 were primarily due to delay rental payments on undeveloped acreage and seismic and micro-seismic activities on our properties.
Depletion, Depreciation, Amortization and Accretion Expense of approximately $28.4 million for 2011 increased approximately $6.6 million, or 30.1%, from 2010. Depletion expenses incurred during 2010 were lower than what would normally be expected primarily due to the carry obligations by our joint venture partners, whereby our partners would fund the majority of the cost to drill and complete wells to earn their share of the working interest. We expect future depletion to trend more in line with production as the carry obligations have been expended, pending any future carry obligations.
Other Operating Expense for 2011 totaled approximately $2.6 million. These costs are comprised of operating expenses incurred in connection with Water Solutions. Water Solutions is a subsidiary of which we own 80% and fully consolidate the results of operations. This entity did not have operating expense prior to 2010.
Interest Expense, net of Interest Income, for 2011 was approximately $2.0 million as compared to $1.0 million for 2010. The increase in interest expense, net of interest income, was primarily due to a higher average outstanding balance on our Senior Credit Facility.
Gain (Loss) on Derivatives, net for 2011 was a gain of approximately $18.9 million as compared to $6.1 million for 2010. This change was attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. 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 gains would suggest the opposite. Our derivative program is designed to provide us with greater predictability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.
Net Income (Loss) Attributable to Rex Energy for 2011 was a loss of approximately $15.4 million, as compared to net income of approximately $6.0 million for 2010 as a result of the factors discussed above.
Comparison of the Year Ended December 31, 2010 to the Year Ended December 31, 2009
Oil and gas revenue for the years ended December 31, 2010 and 2009 is summarized in the following table:
Average realized price received for oil and gas during 2010 was $9.20 per Mcfe, a decrease of 0.5%, or $0.05 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2010 increased 14.0% or $8.63 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 6.8%, or $0.43 per Mcf, from 2009. Our derivative activities effectively increased net realized prices by $0.11 per Mcfe in 2010 and $0.99 per Mcfe in 2009.
Production volume for 2010 increased 25.8% from 2009 primarily due to the success of our Marcellus Shale horizontal drilling plan in the Appalachian Basin, where production increased approximately 108%, or 1.7 Bcfe. Our production for 2010 averaged approximately 20,250 Mcfe per day of which 56.1% was attributable to the Illinois Basin and 43.9% to the Appalachian Basin.
Statements of Operations for the years ended December 31, 2010 and 2009 are as follows:
Other Revenue for 2010 of approximately $1.5 million increased $1.4 million, or 880%, from 2009. These amounts were attributable to the operations of Water Solutions, our 80% owned joint venture that specializes in the sourcing and transportation of water in the Marcellus Shale regions of the Appalachian Basin. Revenues earned by Water Solutions were classified as Other Revenue in 2010 and did not exist prior to 2010.
Production and Lease Operating Expense increased approximately $2.5 million, or 11.3%, in 2010 from 2009. The increase in expense was primarily due to seasonal repair and maintenance work being performed in our Illinois Basin operations. These repair and maintenance activities were delayed during 2009 due, in part, to