PostRock Energy Corporation. Director, 10% Owner Energy L.P. Edelman & Guill bought 3,076,923 shares on 8-01-2012 at $ 1.95
PostRock Energy Corporation (â€śPostRockâ€ť) is a Delaware corporation formed in 2009. It was formed to combine its predecessor entities, Quest Resource Corporation, Quest Energy Partners, L.P. and Quest Midstream Partners, L.P. (collectively, the â€śPredecessorsâ€ť) into a single entity. In March 2010, PostRock completed the combination of these entities (the â€śRecombinationâ€ť). Unless the context requires otherwise, references to â€śwe,â€ť â€śusâ€ť and â€śourâ€ť refer to PostRock from the date of the Recombination and to the Predecessors on a consolidated basis prior thereto.
We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in two segments, production and pipeline. Our production segment is focused in the Cherokee Basin (the â€śBasinâ€ť), a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and gas producing properties in the Appalachian Basin. Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline (the â€śKPC Pipelineâ€ť), which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.
PostRockâ€™s production in the Cherokee Basin is derived from Pennsylvanian Age coal and shale formations. We believe 90% of our current production comes from the coal formations, which are located at depths between 300 and 1,400 feet. In order to understand how to improve our wellsâ€™ performance, we have been conducting and continue to conduct a series of geologic and engineering studies. These studies include a detailed review of fracture stimulation techniques, electric log data and depositional patterns to identify variables that support higher production rates. The studies have enabled us to better understand our production curves and production areas. We are also evaluating the possibility of finding oil and gas reserves in other geologic horizons.
At December 31, 2011, our Cherokee Basin assets consisted of approximately 2,773 gross and 2,758 net wells capable of production. These wells are on approximately 347,364 net acres of leasehold classified as developed. In addition, we have approximately 117,499 net acres classified as undeveloped in the Cherokee Basin. During 2011, our net production from these wells was an average of 48.5 Mmcfe/d. At year end, our reservoir engineers attributed 109.9 Bcfe of estimated net proved reserves to these properties.
We also have a gathering system in the Cherokee Basin. The system provides a market outlet for gas produced in an approximately 1,000 square mile area. The system has connections to one intrastate and three interstate pipelines. We gather substantially all of our production in the Basin. In addition, we gather a minor amount of gas produced by others. At year end, throughput on the system averaged 62.5 Mmcf/d of which approximately 3.6 MMcf/d and 10.6 MMcf/d was attributable to third parties and to our royalty owners, respectively. Third-party gathering contracts generally permit us to retain 20% to 30% of the gas gathered. We believe ownership of the system is a material competitive advantage in the future development and consolidation of assets in the Basin. The gathering system includes 74 leased compressors totaling approximately 51,000 horsepower and six CO 2 amine treating facilities. The system has an estimated throughput capacity of approximately 85 Mmcf/d. Based on net production in 2011, we believe we are the largest producer of gas in the Cherokee Basin with net production equal to approximately two times that of Constellation Energy Partners LLC (â€śCEPâ€ť), the second largest producer in the Basin . We also believe that we have the largest gathering system in the Basin.
At December 31, 2011, our Oklahoma oil assets consisted of approximately 24 gross and 22.5 net wells capable of production. These wells are on approximately 1,360 net acres of leasehold classified as developed. In addition, we have approximately 120 net acres classified as undeveloped in central Oklahoma. During 2011, net production from these wells averaged 133 Bbls/d. At year end, our reservoir engineers attributed 0.8 MMBbl of crude oil and 203 Mmcf of natural gas, or a total of 5.1 Bcfe, of estimated net proved reserves to these properties.
As discussed below, we sold the majority of our Appalachian Basin assets in late 2010 and during the first half of 2011. Subsequent to the sale, our remaining assets consist of approximately 488 gross and 457 net wells capable of production. These wells are on approximately 8,870 net acres of leasehold classified as developed. In addition, we have approximately 24,871 net acres classified as undeveloped in the Appalachian Basin. During 2011, net production from our remaining wells was an average of 1.9 Mmcfe/d. At year end, our reservoir engineers attributed 9.7 Bcfe of estimated net proved reserves to these properties.
We also have a 141.1 mile gathering system in the Appalachian Basin. The system is connected to one interstate pipeline. At December 31, 2011, this system had an average throughput of approximately 2.1 Mmcf/d of which approximately 1.6 Mmcf/d was attributable to our net production with the remaining 0.5 Mmcf/d attributable to our royalty or joint interest owners. All of our gas produced in the area is transported by this system.
Appalachian Basin Asset Sale. On December 24, 2010, we entered into an agreement with Magnum Hunter Resources Corporation (â€śMHRâ€ť) to sell to MHR certain oil and gas properties and related assets located in West Virginia. The sale enabled us to reduce debt and focus on the Cherokee Basin. The sale closed in three phases for $44.6 million. The first phase closed in December 2010 for $28 million, and the next two phases closed in January and June 2011 for a combined $16.6 million. The amount received for the first and second phases was paid half in cash and half in MHR common stock, while the amount received for the third phase was paid entirely in cash. Of the proceeds received, $6.4 million was set aside in escrow to cover potential claims for indemnity and title defects. If all of the amounts in escrow are released, we would receive a total of $1.5 million and the remaining amount would be released to our lender and a third party.
CEP Investment. During 2011, we acquired from Constellation Energy Group, Inc. (â€śCEGâ€ť) a 26.4% voting interest in CEP and the right to appoint two directors to CEPâ€™s Board. The investment was consummated in two separate transactions. The first transaction, which included a 14.9% voting interest, closed in August 2011 for $6.9 million in cash and $4.6 million in PostRock equity, while the second transaction, for an additional 11.5% voting interest, closed in December 2011 for $6.1 million in cash. The investment is described further within Part II, Item 7 â€śManagementâ€™s Discussion and Analysis of Financial Condition and Results of Operationsâ€ť in this Annual Report on Form 10-K. CEP is focused on the acquisition, development and production of oil and natural gas properties as well as related midstream assets. Because PostRock and CEP each have the majority of their assets in the Cherokee Basin of Kansas and Oklahoma, the investment was made in an attempt to work with CEP to explore opportunities to reduce costs and enhance value for the companiesâ€™ respective investors. Except where expressly noted, references to reserves, results, production, prices and other statistics included in this Annual Report on Form 10-K exclude amounts related to our interest in CEP.
In June 2011, we agreed to purchase CEGâ€™s roughly 26.4% interest in CEP. Closing was contingent on the approval of CEPâ€™s Board of Managers. After CEPâ€™s Board declined to consider the request, we terminated the agreement, purchasing approximately a 14.9% interest in CEP in August 2011. The less than 15% stake avoided triggering certain anti-takeover provisions of the Delaware statutes. When CEG decided to sell the remainder of their position in December 2011, we elected to purchase it despite the Delaware statute. The purchase increased our ownership position to approximately 26.4%. Under the Delaware statute, a business combination or other corporate transaction with CEP may now not be possible prior to December 2014. Despite their prior lack of support, we continue to hope the Board and management of CEP will work with us to explore opportunities for increased efficiency in the Cherokee Basin. The importance of efficiency has obviously increased dramatically as gas prices languish below $3.00/Mcf in early 2012. Unfortunately, while CEPâ€™s Board has indicated a willingness to discuss these matters, they have insisted that the substance and even the existence of any such discussion remain secret. To date, we have been unwilling to keep the overall status of any discussions from our shareholders.
The KPC Pipeline is one of five pipelines capable of delivering gas to Kansas City. It has a throughput capacity of approximately 160 Mmcf/d. The pipeline includes three compressor stations with a total of 14,680 horsepower. The pipeline has interconnections with pipelines owned and/or operated by Enogex Inc. (â€śEnogexâ€ť), Panhandle Eastern Pipe Line Company (â€śPEPLâ€ť) and ANR Pipeline Company. These connections enable us to transport gas sourced from the Anadarko and Arkoma Basins, as well as the western Kansas and Oklahoma panhandle producing regions. The pipeline is regulated by the Federal Energy Regulatory Commission (â€śFERCâ€ť).
The KPC Pipeline continues to be underutilized, but throughput, revenue and operating expenses in the past year continue to improve. We are working to increase throughput by creating additional service options for gas suppliers and consumers and pursuing additional pipeline interconnects to provide customers greater optionality for gas supply and market. Throughput in 2011 increased 10.1% from the prior year.
We are currently exploring strategic alternatives for the KPC Pipeline. Transactions being considered include a sale or joint venture that may involve conversion of part of the line to crude oil service. We have retained a financial advisor to assist in the process.
Financial information by segment and revenues from external customers are located in Part II, Item 8 â€śFinancial Statements and Supplemental Dataâ€ť to this Annual Report on Form 10-K.
Description of Production Properties and Projects
We produce coal bed methane (â€śCBMâ€ť) gas out of our properties in the Cherokee Basin which is situated between the Forest City Basin to the north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. The Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian limestones, which were developed beginning in the early 1900s.
The principal formations we target include the Mulky, the Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the Basin. Each seam is generally two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations throughout the Basin. These seams range in thickness from one to two feet.
CBM is unique in that the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption leads to gas being stored at relatively low pressures. Another unique characteristic of CBM is that the gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coal bed formations typically require extensive dewatering and de-pressuring before desorption can occur and the methane begins to flow at commercial rates. We use submersible pumps on all new wells for more efficient dewatering, which has reduced the amount of time it takes for our CBM wells to achieve peak production from up to 12 months to as few as 4 months.
CBM and conventional gas both have methane as their major component. While conventional gas often has more complex hydrocarbon gases, CBM rarely has more than 2% of the more complex hydrocarbons. The CBM produced from our Cherokee Basin properties has a BTU content of approximately 990 BTU per cubic foot, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050 â€“ 1,300 BTU per cubic foot. The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the wellbore in a CBM well is determined by the fracture or cleat network in the coal. While, at shallow depths of less than 500 feet, these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow naturally. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal. A slurry of water, certain chemicals and sand is pumped at high pressures into the fractures, with the sand essentially propping the fractures open. After the release of pressure, the flow of both water and gas is improved, allowing the production of gas.
The Appalachian Basin is one of the largest and oldest producing basins in the United States. Our main area of operation in the Appalachian Basin is in West Virginia, where our producing formations range in depth from 1,500 feet to approximately 6,500 feet. Our main production formations are the lower Devonian Marcellus Shale, the shallow Mississippian (Big Injun, Maxton, Berea, Pocono, Big Lime) and the Upper Devonian (Riley, Benson, Java, Alexander, Elk, Cashaqua, Middlesex, West River and Genesee, including the Huron Shale member and Rhinestreet Shales).
With the significant reduction in natural gas prices at the end of 2011, continuing into 2012 and expected for the foreseeable future, our focus for 2012 will be to complete capital projects that retain leases, make existing wells more efficient, or create additional oil production. For 2012, we have budgeted approximately $12.1 million to drill and complete 34 new gas wells in the Basin and five new oil wells in central Oklahoma, and recomplete eight wells in central Oklahoma and 36 wells in the Appalachian Basin. We estimate that for 2012, our average cost for drilling and completing a gas well in the Basin, including the related pipeline infrastructure, will be approximately $149,000. We have also budgeted $ 9.6 million for land, infrastructure and equipment expenditures. We intend to fund our 2012 capital expenditures with cash flow from operations. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. See Item 1A. â€śRisk Factorsâ€”Risks Related to Our Businessâ€”Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations. â€ť
We are developing our Cherokee Basin properties on a combination of 160-acre and 80-acre spacing. Our wells generally reach total depth in 1.5 days. During 2011, we completed 116 gas wells, of which 17 were drilled prior to 2011. Our cost to drill and complete a well, including the related pipeline infrastructure, was approximately $146,000 during 2011. In the second half of the year, we spent a significant amount of time working to better understand the geology and fracture treatments required in the different areas of the Cherokee Basin. We have compiled detailed engineering data and we continue to collect data and to perform studies of this data. We continue to further refine our understanding of the geoscience in the Cherokee Basin to improve individual well results.
We perforate and fracture stimulate the multiple coal seams and formations present in each well. Our typical Cherokee Basin well has net reserves of approximately 110-140 Mmcf depending on the geological setting and averages an initial daily production rate of 5-10 Mcf while water is pumped off and the formation pressure is lowered. Following what has historically been an initial 4 to 12 month dewatering period, there is a 12 to 18 month period of relatively flat net daily production of approximately 40 Mcf. Thereafter, production begins a 10-17% exponential decline. The standard economic life is approximately 21 years. Through the use of submersible pumps, we have been able to shorten the initial dewatering period to approximately four months in most of our new wells.
Our development activities in the Cherokee Basin also include a program to recomplete or convert CBM wells that were originally completed from a single coal seam to wells that produce from multiple coal seams. The recompletion strategy is to add four to five additional pay zones to each wellbore, in a two-stage process at an average cost of approximately $45,000 per well. Adding new zones to an existing well has a brief negative effect on production by first taking the well offline to perform the work and then by introducing a second dewatering phase of the newly completed formations. In the longer term, we believe the impact of the multi-seam recompletions and the introduction of submersible pumps results in increased returns. This is due to an increased rate of production, reduced operating costs and an increase in the ultimate per well recoverable reserves. During 2011, 49 recompletions were undertaken. 33 of these recompletions have demonstrated increased production while the remaining 16 still require additional work in order for any production increase to be quantified. At December 31, 2011, we have identified approximately 30 additional wellbores that are candidates for recompletion to multi-seam producers. We are also in the process of reviewing high cost, low production wells to determine if additional zones are capable of production. We expect this process to result in additional wellbores being identified as candidates for recompletion. In addition to the recompletion projects, we have also reviewed many of the initial stimulations of wells throughout the basin and re-stimulation activities have shown to be successful in two of the three wells recently tested.
Our total capital expenditure in the Appalachian Basin in 2011 was $481,000. Our 2012 capital budget discussed above includes 36 recompletions aimed at achieving higher oil production in the Appalachian Basin.
Oil and Gas Data
Preparation of Reserve Reports
Management has established, and is responsible for, internal controls designed to provide reasonable assurance that our reserve estimation is compared and reported in accordance with rules and regulations promulgated by the Securities Exchange Commission (â€śSECâ€ť) as well as established industry practices used by independent engineering firms and our peers. These internal controls include, but are not limited to: 1) documented process workflow timeline, 2) verification of economic data inputs to information supplied by our internal operations accounting, regional production and operations, land, and marketing groups, and 3) senior management review of internal reserve estimations prior to publication.
Cawley, Gillespie & Associates, Inc. (â€śCGAâ€ť), prepared our reserves estimates at December 31, 2009, 2010 and 2011. CGA is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own any interest in our properties and are not employed on a contingent fee basis. The technical person responsible for our reserve estimates at CGA meets the requirements regarding 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.
Nathan M. Avery , age 77, became a director of PostRock in September 2010 and is a designee of White Deer Energy L.P. as described below under â€śCertain Relationships and Related Transactions, and Director Independence â€” White Deer Investment.â€ť Mr. Avery served as a director of Cameron International Corporation from 1995 until 2009. He was founder, Chairman of the Board and Chief Executive Officer of Galveston-Houston Company, an NYSE company specializing in the manufacturing of products to serve the energy and mining industries, from 1972 to December 2000, when it was sold to Komatsu, Ltd. He has been an active participant in the oil and gas industry since the 1960s and was Chairman of the Board of Directors of Bettis Corporation, an actuator company, until 1996, when Bettis Corporation merged with Daniel Industries, Inc., and was a director and member of the Executive Committee of Daniel Industries until June 1999, when Daniel Industries merged with Emerson Electric Co. Mr. Avery holds a B.S. in Petroleum Engineering from the Colorado School of Mines. The board of directors is nominating Mr. Avery because of his active participation in the oil and gas industry since the 1960s and his strong technical expertise.
Terry W. Carter , age 59, became Interim President and Chief Executive Officer in June 2011 and President and Chief Executive Officer and a director in December 2011. Since February 2008, Mr. Carter has been a principal of a number of private oil and gas ventures. From 2003 through November 2007, Mr. Carter served as President and Chief Executive Officer of Ascent Energy, Inc., a private exploration and production company. In 2001, Mr. Carter became Executive Vice President of Exploration and Production at Range Resources Corporation, an exploration and production company, where he served in that role until 2003. Mr. Carter began his career as a petroleum engineer for ORYX Energy, formerly Sun Exploration and Production. In the course of his more than 20 years with that company, he rose to become Manager of Operations and Development in Dallas. Mr. Carter holds a B.S. in Petroleum Engineering from Tulsa University. The board of directors is nominating Mr. Carter because, in addition to valuing his significant operating experience, the board believes that having his perspective as the Chief Executive Officer of our company enhances the boardâ€™s focus on and contribution to our growth and development and is in the best interest of our stockholders.
William H. Damon III , age 59, became a director of PostRock in March 2010 upon completion of the recombination. Mr. Damon joined QRCP as a director in April 2007 and served in that capacity until March 2010. He has over 35 years of professional experience specializing in engineering design and development of power generation projects and consulting services. Since January 2008, he has served as Senior Vice President and National Director of Power Consulting for HDR, Inc., which purchased the engineering-consulting firm, Cummins & Barnard, Inc., which was focused on power generation development and engineering projects for electric utilities, independent power producers, large industrial and institutional clients throughout the United States. Mr. Damon served as the Chief Executive Officer of Cummins & Barnard and had been its principal and co-owner from 1990 to January 2008. He currently leads HDRâ€™s project development and strategic consulting business for coal, natural gas and renewable energy projects. He previously worked for Consumers Power Company, Gilbert-Commonwealth, Inc. and Alternative Energy Ventures. He also held board seats on a minerals and wind turbine company, MKBY, and a start-up construction company that was sold to Aker Kvaerner Songer, in which he was also a founding member. Mr. Damon graduated from Michigan State University with a B.S. in Mechanical Engineering and continued graduate studies at both Michigan State University and the University of Michigan. The board of directors is nominating Mr. Damon because of his background and experience in the energy industry, his knowledge of compensation practices and risk management from his management experience at both HDR and Cummins & Barnard and his service and performance as Chair of our Compensation Committee.
Thomas J. Edelman , age 61, became a director of PostRock in September 2010 and is a designee of White Deer Energy L.P. Mr. Edelman is currently a Managing Partner of White Deer Energy, an energy private equity fund formed in 2008. Previously, Mr. Edelman founded Patina Oil & Gas Corporation and served as its Chairman and Chief Executive Officer from its formation in 1996 through its merger with Noble Energy, Inc. in 2005. In 2005, he founded BioFuel Energy Corporation and served as its Chairman until 2008. He co-founded Snyder Oil Corporation and was its President from 1981 through 1997. He served as Chairman and Chief Executive Officer and later as Chairman of Range Resources Corporation from 1988 through 2003. From 1980 to 1981, he was with The First Boston Corporation and, from 1975 through 1980, with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman also currently serves as President of Lenox Hill Neighborhood House, a New York based charity, as a Trustee and Chair of the Investment Committee of The Hotchkiss School, a member of the Board of Directors of Georgetown University and a Director of Berenson & Company. Mr. Edelman holds an M.B.A. in Finance from Harvard Business School, graduating as a Baker Scholar, and a B.A. in Political Economy from Princeton University, graduating magna cum laude. The board of directors is, in part, nominating Mr. Edelman because of his expertise in managing publicly traded exploration and production companies.
Duke R. Ligon , age 70, became a director of PostRock in March 2010 upon completion of the recombination. Mr. Ligon served as a director of QMGP from December 2006 to March 2010. Since September 2010, Mr. Ligon has served as our Chairman of the Board. From January 2007 to February 2010, Mr. Ligon was a Legal Strategic Advisor to Loveâ€™s Travel Stops & Country Stores, Inc. and the Executive Director of the Loveâ€™s Entrepreneurship Center of Oklahoma City University. From February 1997 to January 2007, Mr. Ligon served as the Senior Vice President and General Counsel for Devon Energy Corporation. Mr. Ligon is an attorney and has more than 35 years of legal expertise in corporate securities, litigation, governmental affairs and mergers and acquisitions. Prior to joining Devon in 1997, he practiced law for 12 years and last served as a partner at the law firm of Mayer, Brown & Platt in New York City. In addition, he was Senior Vice President and Managing Director for Investment Banking at Bankers Trust Co. in New York City for 10 years. He is also a member of the board of directors of Vantage Drilling Company, Blueknight Energy Partners, L.P., Panhandle Oil and Gas Inc., Pre-Paid Legal Services, Inc. and SteelPath MLP Funds Trust and previously served on the boards of TransMontaigne Partners L.P. and TEPPCO Partners, L.P. Mr. Ligon received an undergraduate degree in chemistry from Westminster College and a law degree from the University of Texas School of Law. The board of directors is nominating Mr. Ligon because his experience with Devon Energy Corporation and his expertise in corporate securities, litigation, governmental affairs and mergers and acquisitions brings a unique perspective to the board of directors.
J. Philip McCormick , age 70, became a director of PostRock in March 2010 upon completion of the recombination. Mr. McCormick was a director of QEGP from November 2008 until March 2010. Mr. McCormick has 26 years of public accounting experience and was in leadership roles at KMG Main Hurdman and KPMG LLP, serving as a member of the board of each firm. Since 1999, Mr. McCormick has been an independent investor and corporate advisor. He was a director and chairman of the audit committee of NASDAQ-listed Advanced Neuromodulation Systems Inc. from 2003 to 2005 until its sale, and he currently serves as a director and member of the Audit Committee of RENN Global Entrepreneurs Fund, Inc. Mr. McCormick holds a B.B.A. degree in Accounting and a Master of Science from Texas A&I University. The board of directors is nominating Mr. McCormick because of his public accounting experience, his experience evaluating financial risks and his performance as Chair of our Audit Committee.
Mark A. Stansberry , age 56, became a director of PostRock in March 2010 upon completion of the recombination. Mr. Stansberry was a director of QEGP from November 2007 until March 2010. Mr. Stansberry currently serves as the Chairman and a director of The GTD Group. He has served as Chairman of The GTD Group since 1998. He has served as Chairman of the Governorâ€™s International Team and Chairman of the Board of Regents of the Regional University System of Oklahoma and has served as Chairman of the State Chamberâ€™s Energy Council in Oklahoma. He also serves on a number of other boards, including Chairman of the Board of Directors of People to People International, and has served as president of the International Society of The Energy Advocates. Mr. Stansberry has testified before the U.S. Senate Energy and Natural Resources Committee and is the author of the book: The Braking Point: Americaâ€™s Energy Dreams and Global Economic Realities. Mr. Stansberry has a B.A. from Oklahoma Christian University and is a graduate of The Fund for American Studies, Georgetown University and of the Intermediate School of Banking, Oklahoma State University. The board of directors is nominating Mr. Stansberry because of his expertise related to the U.S. energy industry and economics.
MANAGEMENT DISCUSSION FROM LATEST 10K
Overview of Our Company
We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in two segments, production and pipeline. Our production segment is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and gas producing properties in the Appalachian Basin. Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline, which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.
Our focus, particularly in the current challenging pricing environment, is on efficiently growing reserves, lowering costs and strengthening our balance sheet. We seek to achieve predictable, long-term production with low costs through effective drilling programs and modern completion techniques, efficient management of our field operations and leveraging our existing resources in the Cherokee Basin. We believe this strategy can be achieved through our vertically integrated operating model which includes a full complement of fracture treating and well servicing equipment, and utilizes the latest artificial lift and well management system technology. When appropriate, we intend to pursue opportunistic acquisitions that are accretive to our existing operations. With the current disparity between oil and natural gas prices, in the near term, we are seeking to extract further returns from our oil producing assets through development projects and selective hedging.
Although we are evaluating strategic alternatives related to our KPC Pipeline, we are also working to increase the amount of gas being transported on the pipeline, creating capacity constraints that we believe will lead to long-term firm transportation agreements.
Financial and Operating Results
During 2011, the U.S. and other economies continued the modest growth which started during 2010. Although year-over-year crude oil prices showed improvement from increased demand, an oversupply of natural gas drove our realized natural gas price down significantly. A combination of this reduction of natural gas prices and lower production volumes due to our reduced development activity beginning in 2009 and continuing through 2011 resulted in lower oil and gas revenue. While our capital spending program was down slightly from the 2010 level, we acquired a 26.4% interest in CEP, completed the sale of certain of our Appalachian Basin producing assets, resolved all of the remaining legacy litigation of our predecessors and continued to strengthen our balance sheet.
How We Evaluate Our Operations
Management uses and expects to continue to use a variety of financial and operational measurements to analyze performance and the health of the business. These measurements focus on rates of return, cost efficiency and cost reductions. Specifically we manage our: (1) volumes produced; (2) quantity of proved reserves; (3) realized prices; (4) gathering throughput volumes, fuel consumption by our facilities and natural gas sales volumes; (5) firm transportation contracted volumes; and (6) lease operating expense, gathering expense, interstate pipeline operating expense, and general and administrative expense.
General Trends and Outlook
We are affected by the overall price levels for oil and natural gas, the volatility of these prices and the basis differential from NYMEX pricing to our sales point pricing. According to the U.S. Energy Information Administration (â€śEIAâ€ť), the Henry Hub spot price averaged $4.00 per Mmbtu in 2011. NYMEX strip prices at February 8, 2012, average $2.999/Mmbtu, $3.366/Mmbtu, and $3.612/Mmbtu, for the forward 12, 24 and 36 month periods. Oil and natural gas prices historically have been very volatile and will likely continue to be so in the future.
We sell the majority of our gas in the Cherokee Basin based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. We sell the majority of our natural gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on local basis. We sell the majority of our oil production under a contract priced at a fixed discount to NYMEX oil prices. The Southern Star prices typically are at a discount to the NYMEX pricing at Henry Hub, the regional pricing point, whereas Appalachian prices typically are at a premium to NYMEX pricing. During 2011, the basis differential in the Cherokee Basin ranged from a discount of $0.24/Mmbtu to a premium of $0.23/Mmbtu. Due to the historical volatility of oil and natural gas prices, we implemented a hedging strategy aimed at reducing the variability of prices we receive for the sale of our future production. See Part II, Item 7A. â€śQuantitative and Qualitative Disclosures About Market Riskâ€ť of this Annual Report on Form 10-K for further details on our hedging activity.
Supply and Demand of Oil and Gas
The EIA estimates that total natural gas consumption increased by 2.7 percent in 2011, and forecasts an increase of 1.3 billion cubic feet per day (Bcf/d), or 2.0%, in 2012. This increase is driven by growth in all sectors with the largest volume increase in the electric power sector. Total natural gas consumption is expected to grow by 1.3 percent in 2013 to 69.14 Bcf/d. Total marketed natural gas production increased by the largest year-over-year volumetric amount in history in 2011, an estimated 4.5 Bcf/d, or 7.4 percent, due in large part to increases in shale gas production. Although low spot and future prices are expected to continue, EIA projects average total production to grow by 2.2 percent in 2012 and 1.0 percent in 2013. These projected increases are driven by high initial production rates from new wells, associated natural gas production from oil drilling and a backlog of uncompleted of unconnected wells going into 2012. The large price difference between petroleum liquids and natural gas on an energy-equivalent basis is expected to contribute to a shift towards drilling for liquids. Increased consumption can only partially offset the effect of record-high natural gas inventories caused by the continued growth in natural gas production and a warm winter. EIA is expecting these factors to lead to decreased gas prices in 2012 increasing slightly in 2013.
EIA expects the recent tightening of world oil markets to moderate in 2012 and resume in 2013. World oil consumption is expected to grow by an annual average of 1.3 million Bbls/d in 2012 and 1.5 million Bbls/d in 2013 while the growth in supply from non-Organization of the Petroleum Exporting Countries (non-OPEC) countries is expected to increase by 0.9 million Bbls/d in 2012 and 0.8 million Bbls/d in 2013. The market is expected to rely on both inventories and significant increases in production of crude oil and non-crude liquids in OPEC member countries to meet world demand growth. There are many significant uncertainties that could push oil prices higher or lower than expected. Should a significant oil supply disruption occur, OPEC members not increase production, or projected non-OPEC projects come online more slowly than expected, oil prices could be significantly higher. The rate of economic recovery, both domestically and globally, also remains uncertain due to a variety of factors including fiscal issues facing national and sub-national governments, Chinaâ€™s efforts to address concerns regarding its growth and inflation rates, and unforeseen production issues. The projected WTI spot price is expected to average $100 per barrel in 2012 and continue to rise, reaching $106 per barrel by the end of 2013.
We initially budgeted $43.6 million for drilling and development in 2011. Our actual expenditures for the year totaled $23.8 million, for which we drilled and connected 99 development wells, completed 17 new wells drilled in prior years and recompleted 49 wells. Our lower spending levels relative to budgeted figures from the beginning of 2011 were a reflection of depressed gas prices and the clear need to better understand the results of our drilling activity.
In order to understand how to improve our wellsâ€™ performance, we have been conducting and continue to conduct a series of geologic and engineering studies. These studies include a detailed review of fracture stimulation techniques, electric log data and depositional patterns to identify variables that support higher production rates. The studies have enabled us to better understand our production curves and production areas. We are also evaluating the possibility of finding conventional oil and gas reserves in other geologic horizons.
With the significant reduction in natural gas prices at the end of 2011, continuing into 2012 and expected for the foreseeable future, our focus for 2012 will be to complete capital projects that retain leases, make existing wells more efficient, or create additional oil production. For 2012, we have budgeted approximately $12.1 million to drill and complete 34 new gas wells in the Basin and five new oil wells in central Oklahoma, and recomplete eight wells in central Oklahoma and 36 wells in the Appalachian Basin. We intend to fund our 2012 capital expenditures with cash flow from operations. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. See Item 1A. â€śRisk Factorsâ€”Risks Related to Our Businessâ€”Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations.â€ť
Oil and gas sales decreased $8.0 million, or 9.2%, from $87.9 million for the year ended December 31, 2010, to $79.9 million for the year ended December 31, 2011. This decrease was equally due to reduced production volumes and lower average realized natural gas prices. Cherokee Basin production decreased 569 Mmcfe due to lower than planned development activity and natural production declines while Appalachian Basin production decreased 330 Mmcfe from the prior year primarily due to the divesture of the Appalachian Basin properties. Average realized natural gas prices decreased from $4.47 per Mcfe in 2010 to $4.25 per Mcfe in 2011. Oil and gas sales exclude hedge settlements.
Gathering revenue decreased $608,000, or 10.4%, from $5.8 million during the year ended December 31, 2010, to $5.2 million during the year ended December 31, 2011. The decrease was primarily the result of decreased third-party volumes transported and lower natural gas prices. The majority of our third-party gathering revenue is priced based on a percentage of gas volumes. With lower prices, other producers produced less and the gas we retained was at a lower rate per Mcfe. The effects of the Oklahoma and Kansas royalty settlements also reduced gathering revenue during the fourth quarter and will continue to reduce gathering revenue in the future.
Pipeline revenue increased $1.1 million, or 10.4%, from $10.1 million during the year ended December 31, 2010, to $11.2 million during the year ended December 31, 2011. The increase was primarily due to higher revenues from firm transportation contracts as well as higher commodity revenue due to an increase in throughput.
Production expense consists of lease operating expenses, severance and ad valorem taxes and gathering expense. Production expense increased $162,000, or 0.3%, from $47.0 million during the year ended December 31, 2010, to $47.1 million during the year ended December 31, 2011. The slight increase was due to increased labor, workover and repair and electricity costs of $2.4 million partially offset by lower compression, vehicle and equipment, production and ad valorem taxes of $2.2 million. Production expense per Mcfe increased $0.12, or 5.0%, roughly the amount of the production decrease, from $2.39 per Mcfe during the year ended December 31, 2010, to $2.51 per Mcfe during the year ended December 31, 2011.
Pipeline expense decreased $1.1 million, or 17.2%, from $6.3 million during the year ended December 31, 2010, to $5.2 million during the year ended December 31, 2011. The decrease was due to our December 2010 partial termination of a capacity lease and the leaseâ€™s subsequent expiration in October 2011, partially offset by the costs of gas lost during an external leak in the first quarter of 2011.
Depreciation, depletion and amortization in our production segment increased approximately $4.7 million, or 24.1%, from $19.4 million during the year ended December 31, 2010, to $24.1 million during the year ended December 31, 2011. On a per unit basis, we had an increase of $0.29 per Mcfe from $0.99 per Mcfe during the year ended December 31, 2010, to $1.28 per Mcfe during the year ended December 31, 2011. The increase was primarily due to the reclassification of our gathering system from our pipeline segment to our production segment during the fourth quarter of 2010. This resulted in the gathering system being depleted under a higher rate.
Depreciation and amortization expense in our pipeline segment increased $136,000, or 4.0%, from $3.4 million during the year ended December 31, 2010, to $3.5 million during the year ended December 31, 2011.
Gain from the disposal of production segment assets decreased $3.0 million or 22.2%, from $13.6 million during the year ended December 31, 2010, to $10.6 million during the year ended December 31, 2011. The gain in 2010 was primarily related to the first phase of the Appalachian Basin asset sale while the gain in 2011 was primarily related to the second and third phases of that sale partially offset by $1.9 million of losses on the disposal of excess equipment.
General and administrative expenses decreased $7.6 million, or 30.6%, from $24.8 million during the year ended December 31, 2010, to $17.2 million during the year ended December 31, 2011. As a result of our Recombination and refinancing activities in 2010, we have been able to eliminate significant consulting and other outside service costs associated with those transactions.
Litigation reserve increased $10.0 million, from $1.6 million during the year ended December 31, 2010, to $11.6 million for the year ended December 31, 2011. The expense in 2010 was primarily related to our securities lawsuits. The expense during 2011 is due to settlement costs for our royalty owner lawsuits in Oklahoma and Kansas. The royalty owner lawsuits included allegations that we failed to properly make payments to certain royalty owners in the past. Our Oklahoma royalty owner lawsuits were settled and funded in July 2011 for $5.6 million. Our Kansas royalty owner lawsuits were settled for $7.5 million; the first payment of $3.0 million was made in January 2012, and an additional $4.5 million payment will be made by January 31, 2013. As part of these settlements, all ambiguity in the calculation of prospective as well as prior royalties in our lease agreements will be eliminated. Going forward, we will charge post-production costs to royalty and overriding royalty interest owners pursuant to an agreed upon formula derived as part of the settlements. These settlements comprise the last material litigation or dispute related to our predecessor entities or management. The expense recorded in 2011 for these lawsuits established the $5.6 million reserve for the Oklahoma matters and increased the reserve for the Kansas lawsuit by $6.0 million.
Recovery of misappropriated funds was $1.6 million for the year ended December 31, 2010. The amount represents recovery of a portion of the funds misappropriated between 2005 and 2007 by former officers. No additional amounts were recovered in 2011.
Gain from derivative financial instruments decreased $37.7 million, or 51.5%, from a gain of $73.1 million during the year ended December 31, 2010, to a gain of $35.4 million during the year ended December 31, 2011. We recorded a $41.2 million unrealized gain and a $31.9 million realized gain on our derivative contracts for the year ended December 31, 2010. We recorded a $1.7 million unrealized gain and a $33.7 million realized gain on our derivative contracts for the year ended December 31, 2011.
Interest expense, net, decreased $14.8 million, or 58.0%, from $25.5 million during the year ended December 31, 2010, to $10.7 million during the year ended December 31, 2011. The decrease is primarily due to the September 2010 refinancing, which resulted in a lower balance of debt, lower interest rates and decreased amortization of debt issuance costs. Amortization of debt issuance costs, which is a component of interest expense, was $6.1 million lower in 2011 compared to 2010.
Gain on forgiveness of debt decreased $1.3 million, or 43.4%, from $2.9 million during the year ended December 31, 2010, to $1.6 million during the year ended December 31, 2011. Both gains are the result of our debt restructuring, discussed below, in connection with the QER Loan.
Loss from equity investment was $4.6 million during the year ended December 31, 2011. The loss is a result of a decline in the market price of CEPâ€™s publicly traded equity, which consequently reduced the value of our investment.
Depreciation, depletion and amortization in our production segment decreased approximately $20.1 million, or 50.8%, from $39.5 million during the year ended December 31, 2009, to $19.4 million during the year ended December 31, 2010. On a per unit basis, we had a decrease of $0.82 per Mcfe from $1.81 per Mcfe during the year ended December 31, 2009, to $0.99 per Mcfe during the year ended December 31, 2010. The amounts above include depreciation associated with our gathering system which was reclassified from our pipeline segment to our production segment during the fourth quarter of 2010. Prior to the reclassification, depreciation on the gathering system during the first three quarters of 2010 was $3.2 million lower than the comparable period in 2009. The decrease was a result of the impairment recorded during the fourth quarter of 2009 which lowered the depreciable basis of that asset. Absent depreciation from our gathering system, depreciation, depletion and amortization also decreased due to lower production and a lower depletion rate. Our depletion rate was lower in 2010 as a result of an increase in proved reserves relative to the prior year.
Depreciation and amortization expense in our pipeline segment decreased $4.9 million, or 58.9%, from $8.4 million during the year ended December 31, 2009, to $3.5 million during the year ended December 31, 2010. The decrease was due to an impairment charge of $53.6 million recorded during the fourth quarter of 2009, which subsequently lowered the depreciable basis of these assets.
Gain from the disposal of production segment assets of $13.5 million during the year ended December 31, 2010, was primarily related to the first phase of the Appalachian Basin asset sale in December 2010.
Impairment of our production properties of $215.1 million for 2009 was recorded, while no impairment was recorded in 2010. Our impairment in 2009 included $102.9 million during the first quarter of 2009 as a result of the ceiling test and $112.2 million during the fourth quarter of 2009 related to our gathering system assets prior to their reclassification into the full cost pool during 2010. Our gathering system impairment resulted from a reduction in projected future gathering revenues partially the result of capital expenditure limits contained in our former credit facilities. Impairment of our pipeline assets and related contract intangibles was $53.6 million in 2009 while no such impairment was required in 2010. The impairment in 2009 was a result of the expiration of a significant firm transportation contract in October 2009.
General and administrative expenses decreased $15.9 million, or 39.1%, from $40.7 million during the year ended December 31, 2009, to $24.8 million during the year ended December 31, 2010. Legal, accounting, consulting fees and fees paid to financial advisors decreased as a result of the completion of the reaudit and restatement of previously issued financial statements and the Recombination.
Litigation reserve increased $610,000, from $1.0 million for the year ended December 31, 2009, to $1.6 million for the year ended December 31, 2010. The expense in 2010 was primarily related to our federal securities lawsuits while the expense in 2009 was primarily for the initial estimate to resolve our Kansas royalty owner lawsuits. As discussed previously, we reached an agreement to settle our Kansas royalty lawsuits in December 2011.
Recovery of misappropriated funds was $3.4 million during the year ended December 31, 2009, compared to $1.6 million during the year ended December 31, 2010. These amounts represent recoveries of funds misappropriated between 2005 and 2007 by former officers.
Gain from derivative financial instruments increased $25.0 million from $48.1 million during the year ended December 31, 2009, to a gain of $73.1 million during the year ended December 31, 2010. We recorded a $50.0 million unrealized loss and a $98.1 million realized gain on our derivative contracts for the year ended December 31, 2009, compared to a $41.2 million unrealized gain and a $31.9 million realized gain for the year ended December 31, 2010. The decrease in realized gain was the result of contracts with higher settlement prices and a one-time gain of $26 million when we exited certain contracts in order to pay down debt in 2009.
Interest expense, net, decreased $3.9 million, or 13.1%, from $29.4 million during the year ended December 31, 2009, to $ 25.5 million during the year ended December 31, 2010. The decrease was primarily due to the continuing positive effect on underlying rates as a result of our September 2010 refinancing, repayments of debt and lower interest rates on our restructured credit facilities.
Gain on forgiveness of debt was $2.9 million for the year ended December 31, 2010; the gain was recorded in connection with the restructuring of our QER Loan discussed below.
Liquidity and Capital Resources
We have reduced our overall debt outstanding from $220.2 million at December 31, 2010 to $193.0 million at December 31, 2011, or 12%. Our debt reduction was achieved primarily through the settlement of our QER Loan utilizing proceeds from the Appalachian Basin asset sale and the retirement of our Secured Pipeline Loan.
Historical Cash Flows and Liquidity
Cash flows from operating activities have historically been driven by the quantities of our production, the prices received from the sale of this production, and from our pipeline revenue. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of production operating costs, severance and ad valorem taxes, interest on our indebtedness and general and administrative expenses.
Cash flows from operations totaled $74.6 million, $38.8 million and $42.7 million for the years ended December 31, 2009, 2010 and 2011, respectively. The increase from 2010 to 2011 is primarily due to lower interest charges and general and administrative expenses compared to the prior year coupled with higher realized gains on derivative contracts. These increases more than offset a decrease in cash flow due to the decline in oil and gas revenues in 2011. The decrease from 2009 to 2010 is attributable primarily to a decrease in realized gains on our derivatives offset by changes in working capital. The decrease in realized derivative gain was the result of a one-time gain of $26 million in 2009 when we re-priced certain contracts in order to pay down debt.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
PostRock Energy Corporation (â€śPostRockâ€ť) is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in two segments, production and pipeline. Our production segment is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and gas producing properties in the Appalachian Basin. Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline, which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.
The following discussion should be read together with the unaudited consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2011.
2012 Drilling Program Update
For 2012, we budgeted approximately $12.1 million to drill and complete 34 new gas wells in the Cherokee Basin and five new oil wells in central Oklahoma, and recomplete eight oil wells in central Oklahoma and 36 oil wells in the Appalachian Basin. In addition, we budgeted $9.6 million for land, infrastructure and equipment. During 2012, we recompleted 18 wells to increase oil production. Capital spending in the first quarter of 2012 included $1.6 million on drilling and recompletions, $1.4 million to complete our vehicle and equipment efficiency projects, $913,000 to connect two sections of our gathering system to improve production, $751,000 to complete our consolidation and upgrade of facilities in the Cherokee Basin, $62,000 to extend leases in the Cherokee Basin and $113,000 on our interstate pipeline. Our capital spending for the remainder of 2012 is subject to available capital as discussed below in â€ś Sources of Liquidity in 2012 and Capital Requirements. â€ť
The significant reduction in natural gas prices at the end of 2011 has continued into 2012, falling below $2.00 per MMbtu in April 2012, and prices are not expected to return to economic levels for some time. As a result, we have curtailed all capital expenditures related to natural gas and have redirected our remaining budgeted drilling capital to oil development opportunities on existing leasehold. These opportunities include the potential for behind-pipe recompletions, workovers and new drilling locations. While we are still in the early stages of testing this potential, results from initial efforts are encouraging. From the 18 oil recompletions we have performed to date in the Cherokee Basin, seven are currently producing oil, four will not produce oil and results are still pending on the remaining seven. The seven wells currently producing oil are flowing 26 net barrels a day in total. While it is too soon to draw broad conclusions, successful results in these initial tests could add up to 300 recompletion and 300 new well opportunities.
Oil and gas sales decreased $6.6 million, or 32.7%, from $20.2 million during the three months ended March 31, 2011 to $13.6 million during the three months ended March 31, 2012. Decreased average realized natural gas prices reduced revenue by $5.8 million and lower production volumes reduced revenue by $1.0 million. These decreases were slightly offset by increased oil production volumes and prices. Our average realized prices on an equivalent basis (Mcfe) decreased from $4.33 per Mcfe for the three months ended March 31, 2011, to $3.08 per Mcfe for the three months ended March 31, 2012. Oil and gas sales exclude any realized or unrealized hedging gains or losses.
Gathering revenue decreased $657,000, or 48.5%, from $1.4 million for the three months ended March 31, 2011 to $699,000 for the three months ended March 31, 2012. The decrease is primarily due to the settlement of the royalty lawsuits in late 2011 which lowered the rates that we are paid for gathering royalty interest gas. A decline in production volumes also contributed to the decrease.
Pipeline revenue increased $255,000, or 8.0%, from $3.2 million for the three months ended March 31, 2011 to $3.4 million for the three months ended March 31, 2012. The increase was due to higher volumes transported associated with oil production in Osage County, Oklahoma.
Production expense consists of lease operating expenses, production taxes and gathering expense. Production expense decreased $933,000, or 7.5%, from $12.4 million for the three months ended March 31, 2011, to $11.5 million for the three months ended March 31, 2012. The decrease was in part due to field optimization projects we began in the latter half of 2011, which resulted in decreased labor, vehicle and equipment costs of $741,000 and decreased gathering costs of $239,000. Also contributing to the decrease was a reduction in production taxes of $912,000 primarily due to lower gas prices and production. These reductions were offset by decreased capitalized expenses of $569,000 due to reduced drilling activity, a one-time charge of $368,000 related to our March 2012 field reorganization and a $22,000 increase across various other expense items. We believe that the field reorganization will result in annual savings of $2.0 million from reduced labor and equipment costs. Production costs were $2.66 per Mcfe for the three months ended March 31, 2011 as compared to $2.60 per Mcfe for the three months ended March 31, 2012. Excluding the one-time charge, production costs for the current quarter were $2.51 per Mcfe.
Pipeline expense decreased $778,000, or 46.9%, from $1.7 million during the three months ended March 31, 2011, to $882,000 during the three months ended March 31, 2012. Costs were higher in the prior year period due to $335,000 of costs related to an external gas leak and $261,000 of costs related to a pipeline capacity lease that was negotiated lower in January 2011 and finally expired at the end of October 2011.
Depreciation, depletion and amortization increased $122,000, or 1.8%, from $6.9 million during the three months ended March 31, 2011, to $7.0 million during the three months ended March 31, 2012. Depletion and amortization on our production properties increased approximately $211,000, or 3.5%, from $6.0 million during the three months ended March 31, 2011 to $6.2 million during the three months ended March 31, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. On a per unit basis, we had an increase of $0.12 per Mcfe from $1.27 per Mcfe during the three months ended March 31, 2011 to $1.39 per Mcfe during the three months ended March 31, 2012. Depreciation and amortization expense on our pipeline segment decreased $89,000, or 9.5%, from $940,000 during the three months ended March 31, 2011, to $851,000 during the three months ended March 31, 2012.
Gain from the disposal of assets of $9.9 million during the three months ended March 31, 2011, was primarily due to the second phase of the Appalachian Basin sale in January 2011.
General and administrative expenses decreased $309,000, or 6.3%, from $4.9 million during the three months ended March 31, 2011, to $4.6 million during the three months ended March 31, 2012. The decrease was primarily due to a $306,000 workmanâ€™s compensation claim paid in the first quarter of 2011.
Litigation reserve expense was $9.5 million during the three months ended March 31, 2011. The expense was recorded to increase our litigation reserve to the estimated potential cost to resolve royalty owner lawsuits pending in Oklahoma and Kansas at the time. The Oklahoma lawsuit was settled in 2011 for $5.6 million which was paid in July 2011. The Kansas lawsuit was settled in 2011 for $7.5 million which included $3.0 million paid in January 2012 and $4.5 million to be paid by January 31, 2013. As part of these settlements, all ambiguity in the calculation of prospective as well as prior royalties in our lease agreements was eliminated. Subsequent to the settlements, we are charging post-production costs to royalty and overriding royalty interest owners pursuant to an agreed upon formula derived as part of the settlements.
Other income (expense) consists primarily of gains (losses) from derivative instruments, gains (losses) from equity investments and net interest expense. Gain from derivative financial instruments increased $12.8 million from a loss of $821,000 for the three months ended March 31, 2011, to a gain of $12.0 million for the three months ended March 31, 2012. We recorded unrealized losses of $10.0 million and $60,000 for the three months ended March 31, 2011 and 2012, respectively. We recorded realized gains of $9.2 million and $12.1 million for the three months ended March 31, 2011 and 2012, respectively. We recorded a mark-to market gain on our equity investment in Constellation Energy Partners LLC (â€śCEPâ€ť) of $4.2 million for the three months ended March 31, 2012 with none recorded in the prior year quarter. Interest expense, net, was consistent year over year at $2.7 million for the three months ended March 31, 2011 and 2012, respectively.
Liquidity and Capital Resources
Cash flows from operating activities have historically been driven by the quantities of our production, the prices received from the sale of this production, and from our pipeline revenue. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of production operating costs, production taxes, interest on our indebtedness and general and administrative expenses.
Our primary sources of liquidity for the three months ended March 31, 2012, were cash generated from our operations and hedging activities, the sale of common stock to White Deer Energy L.P. and its affiliates (â€śWhite Deerâ€ť) and borrowings under our borrowing base credit facility. At March 31, 2012, we had decreased our debt by $14.0 million from December 31, 2011.
Sources of Liquidity in 2012 and Capital Requirements
We rely on our cash flows from operating activities as a source of internally generated liquidity. During the past three years, our cash flows from operating activities have been sufficient to fund our investing activities. Our long-term ability to generate liquidity internally depends in part on our ability to hedge future production at attractive prices as well as our ability to control operating expenses. This has become especially critical in light of current depressed natural gas prices. To a lesser extent, we have in the past relied on the sale of our non-core production assets to generate liquidity. From time to time, we may also issue equity as an external source of liquidity. On February 9, 2012, we issued 2,180,233 shares of our common stock to White Deer for proceeds of $7.5 million which were used to retire the Secured Pipeline Loan and for other general corporate purposes.
At March 31, 2012, we have a $350 million secured borrowing base revolving credit facility with a borrowing base of $200 million. With borrowings of $179 million and $1.6 million in outstanding letters of credit, we had $19.4 million available under the facility on that date.
We are currently in discussions with our lenders regarding a borrowing base redetermination of the facility based on our oil and gas reserves at December 31, 2011. Primarily as a result of the decline in natural gas price assumptions and the roll off of gas hedges, the borrowing base is expected to be lowered no less than $23 million to $177 million. Given current gas prices, we do not anticipate having meaningful liquidity for some time. We expect to fund working capital and capital expenditures with cash flow from operations and cash on hand.
We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity securities under the shelf registration statement in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. The registration statement is intended to give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual amount and type of securities or combination of securities and the terms of those securities will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to that offering will set forth our intended use of the net proceeds. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated transactions, subject to our approval. Our sales agreement is limited to the sale of up to a number of shares of common stock with an initial offering price not to exceed the amount that can be sold under the registration statement. As of the date of the sales agreement, such amount is limited to approximately $20.3 million. As of March 31, 2012, we had not issued any shares of common stock pursuant to the sales agreement.
We are continuing our strategic review of the KPC Pipeline. The review includes a potential sale of the asset which, if consummated, would generate cash and improve our liquidity. Potential buyers are currently engaged in due diligence.
During April 2012 we repriced the portion of our natural gas swap contracts expected to settle in June, July and August of 2012 to market prices for proceeds of $10.8 million. The proceeds will be utilized to reduce our debt.
At March 31, 2012, including 2,180,233 shares of our common stock held by White Deer, we had 12,268,970 shares of common stock issued and outstanding. In addition, we have 22,915,155 outstanding warrants to purchase our common stock of which 22,241,333 are owned by White Deer at an average exercise price of $3.23 and 673,822 are owned by Constellation Energy Group Inc. at an average exercise price of $7.07. We also have 114,966 unvested restricted stock units and 1,140,620 options outstanding granted under our long term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 36,439,711 of which the warrants and common stock owned by White Deer represent approximately 67%. By exercising their warrants, White Deer can benefit from their respective percentage of all of our profits and growth. In addition, if White Deer begins to sell significant amounts of our common stock, or if public markets perceive that they may sell significant amounts of our common stock, the market price of our common stock may be significantly impacted.
We have numerous contractual commitments in the ordinary course of business, including debt service requirements, purchase obligations and operating lease commitments. Except for the debt repayments during the first quarter of 2012, at March 31, 2012, there were no other material changes to our contractual commitments since December 31, 2011.
Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.
When we use the words â€śbelieve,â€ť â€śintend,â€ť â€śexpect,â€ť â€śmay,â€ť â€świll,â€ť â€śshould,â€ť â€śanticipate,â€ť â€ścould,â€ť â€śestimate,â€ť â€śplan,â€ť â€śpredict,â€ť â€śproject,â€ť or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:
â€˘current weak economic conditions;
â€˘volatility of oil and natural gas prices;
â€˘increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
â€˘our debt covenants;
â€˘access to capital, including debt and equity markets;
â€˘results of our hedging activities;
â€˘drilling, operational and environmental risks; and
â€˘regulatory changes and litigation risks.
You should consider carefully the statements under Item 1A. Risk Factors included in our annual report on Form 10-K for the year ended December 31, 2011, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our annual report on Form 10-K for the year ended December 31, 2011, is available on our website at www.pstr.com .
We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.