UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2010

 

Commission file number: 001-34635

 

PostRock Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

 

 

Registrant’s telephone number, including area code:

(405) 600-7704

Securities Registered Pursuant to Section 12(b) of the Exchange Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes o     No þ

 

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 þ     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 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 o     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s 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.  o

 

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

 

The aggregate market value of common stock held by non-affiliates of the registrant at June 30, 2010, was approximately $32 million, based upon the closing price of $4.72 per share as reported by the NASDAQ on such date.

 

The aggregate market value of outstanding common stock, including those held by affiliates of the registrant, at March 1, 2011, was approximately $52 million, based upon the closing price of $6.24 per share. There were 8,290,482 shares of common stock outstanding on that date.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the proxy statement for the 2010 Annual Meeting of Stockholders are incorporated by reference in Part III.

 

 

TABLE OF CONTENTS

 

GLOSSARY

 

In this report the following abbreviations are used:

 

 

This report contains forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Item 1A. “Risk Factors — Disclosure Regarding Forward-Looking Statements.”

 

 

Background

 

PostRock Energy Corporation (“PostRock” or the “Company”) is a Delaware corporation formed in 2009 to combine our predecessor entities, Quest Resource Corporation (“QRCP”), Quest Energy Partners, L.P. (“QELP”) and Quest Midstream Partners, L.P. (“QMLP”) into a single company. In March 2010, we completed the combination of these entities (the “Recombination”). Unless the context requires otherwise, references to the “Company,” “we,” “us” and “our” refer to PostRock from the date of the Recombination and to the three predecessor entities on a consolidated basis prior thereto.

 

Business Segments

 

We are an independent oil 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 certain other minor gas producing properties in the Appalachian Basin.

 

Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline (the “KPC Pipeline”), which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City. We acquired the KPC Pipeline in November 2007.

 

Production

 

Our 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 1400 feet. In order to understand how to improve our wells’ performance, we are conducting 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. We are also evaluating the possibility of finding conventional gas reserves in other geologic horizons.

 

At December 31, 2010, our Cherokee Basin assets consisted of approximately 2,659 gross and 2,643 net wells capable of production. These wells are on approximately 336,287 net acres of leasehold classified as developed. In the Basin, we have approximately 132,590 net acres currently classified as undeveloped. During 2010, these wells produced at an average daily rate of 50.1 Mmcfe. At year end, our reservoir engineers attributed 121.5 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 1 intrastate and 3 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, daily throughput on the system averaged 64.6 Mmcf of which approximately 6.0% was produced by third parties. Third party gathering contracts generally permit us to retain between 20% and 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 77 compressors totaling approximately 53,000 horsepower and six CO₂ amine treating facilities. The majority of this compression is rented. The system has an estimated throughput capacity of approximately 85 Mmcf per day. We believe we are the largest producer of gas and have the largest gathering system in the Cherokee Basin.

 

At December 31, 2010, our Oklahoma assets consist of approximately 39 gross and 22.5 net wells capable of production. These wells are on approximately 1,481 net acres of leasehold classified as developed and additionally, we have approximately 25 net acres classified as undeveloped. During 2010, these wells produced net to our interest at an average daily rate of 170 Bbls. At year end, our reservoir engineers

attributed 603,840 Bbls of crude oil and 74.2 Mmcf of natural gas, or a total of 3.7 Bcfe, of estimated net proved reserves to these properties.

 

Giving effect to the sale discussed below, our Appalachian Basin assets consist of approximately 400 gross and 373 net wells capable of production. These wells are on approximately 9,291 net acres of leasehold classified as developed. In this area, we also have approximately 26,815 net acres currently classified as undeveloped. During 2010, these wells produced at an average daily rate of 2.8 Mmcfe, of which approximately 33% was from the properties sold. At year end, also giving effect to the sale discussed below, our reservoir engineers attributed 9.0 Bcfe of estimated net proved reserves to these properties.

 

We also have a 163 miles gathering system in the Appalachian Basin. The system is connected to two interstate pipelines. At December 31, 2010, this system had a maximum daily throughput of approximately 3 Mmcf. All of our gas production 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 (“MHR”) to sell to MHR certain oil and gas properties and related assets located in Wetzel and Lewis Counties, West Virginia. The sale enabled us to reduce debt and focus on the Cherokee Basin. The sale closed in two phases for $39.7 million. The first phase covered assets located in the Wetzel County which closed on December 30, 2010 for $28 million. The second phase covered assets located in Lewis County which closed on January 14, 2011 for $11.7 million. The amount received at both closings was paid half in cash and half in MHR common stock. The agreement contained provisions for a third closing if certain conditions are met before May 15, 2011. There can be no assurance that the third closing will occur.

 

Interstate Pipeline

 

Our pipeline is one of four pipelines capable of delivering gas to Kansas City. It has a daily throughput capacity of approximately 160 Mmcf. The pipeline includes three compressor stations with a total of 14,680 horsepower. The majority of this compression is owned. Our pipeline has interconnections with pipelines owned and/or operated by Enogex Inc. (“Enogex”), Panhandle Eastern Pipe Line Company (“PEPL”) 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 KPC Pipeline is significantly underutilized. To address this problem, we have hired a new KPC Pipeline management team and shut down our Houston office in the course of the last 18 months. Currently, all pipeline management personnel are located in the Oklahoma City corporate office. We are working to increase throughput by creating additional service options for gas suppliers and consumers and developing additional pipeline interconnects to provide customers greater optionality for gas supply and market. In 2010, we added a bidirectional interconnect with PEPL and a delivery capability with Enogex. These interconnects provide our shippers new opportunities. Throughput in 2010 increased 37% from prior year levels and we added 12 new shippers. We have not been able to increase the amount of our capacity that is subject to long-term firm transportation contracts. Our goal is to increase the amount of gas being transported on our pipeline, thereby creating capacity constraints that we believe will lead to long-term firm transportation agreements. To achieve this, we continue to evaluate multiple possibilities, such as transporting gas for producers in close proximity to our pipeline, each intended to create value for the customer while providing incremental profit for the KPC Pipeline.

 

The KPC Pipeline is regulated by the Federal Energy Regulatory Commission (“FERC”).

 

Financial information by segment and revenues from external customers are located in Part II, Item 8 “Financial Statements and Supplemental Data” to this Annual Report on Form 10-K.

 

Description of Production Properties and Projects

 

Properties

 

We produce Coal Bed Methane (“CBM”) gas out of our properties located in the Cherokee Basin. Geologically, it 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 Cherokee 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 Cherokee Basin is part of the Western Interior Coal Region of the central United States. The principal formations we target include the Mulky, Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the basin. Each of these seams generally range from 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 and recompletions for more efficient dewatering, which has reduced the amount of time it takes for our CBM wells to achieve peak production rates 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- 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 economic 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 there are producing formations at depths of 1,500 feet to approximately 8,000 feet. Specifically, 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).

 

Projects

 

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 2010, we completed 163 wells, of which 124 wells were drilled prior to 2010. Our cost to drill and complete a well, including the related pipeline infrastructure, was approximately $156,000 during 2010. Although the majority of our project work in the first half of the year was delivered on schedule and under budget, a number of wells did not achieve peak production rate as expected. 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 are continuing to collect data and to

perform studies of this data. Based on preliminary findings, we are evaluating the possibility of finding more conventional gas reserves in other geologic zones. Individual well results from the wells drilled in the third and fourth quarter have been mixed, but on the whole these wells are meeting cumulative production targets as budgeted. We continue to further refine our understanding of the geoscience in the Cherokee Basin to improve individual well results.

 

For 2011, we have budgeted approximately $43.6 million to drill and complete 290 new wells, complete 8 wells drilled in 2010, and recomplete 40 wells. We estimate that for 2011, our average cost for drilling and completing a well, including the related pipeline infrastructure, will be approximately $140,000. The majority of these new wells will be completed on locations that are classified as containing proved reserves in the December 31, 2010 reserve report. We have budgeted $7.3 million for land and equipment capital expenditures. We intend to fund our 2011 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. “Risk Factors — Risks Related to Our Business — 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.”

 

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 daily production at approximately 40 Mcf, net of shrink. Thereafter, production begins to decline. The standard economic life is approximately 15 years. Through the use of submersible pumps, we have been able to shorten the initial dewatering period closer to 4 months in substantially all 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 $36,000 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 long term, we believe the impact of the multi-seam recompletions and the introduction of submersible pumps to the recompleted wells will result in an increased rate of return. This is due to an increased rate of production, reduced operating costs and an increase in the ultimate recoverable reserves available per well. During 2010, 31 recompletions were undertaken, 29 of which were successfully finished. At December 31, 2010, we believe we have approximately 132 additional wellbores that are candidates for recompletion to multi-seam producers.

 

During 2010, we drilled three vertical wells in Wetzel County, West Virginia, and had a working interest in two horizontal wells drilled in Lewis County, West Virginia. We experienced significant drilling cost overruns on the wells in which we participated. All five wells were sold to MHR as described above. Our total capital expenditure in the Appalachian Basin in 2010 was $4.3 million. Our 2011 budget does not include any capital expenditure 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 (“SEC”) 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. (“CGA”), third-party reserve engineers, prepared our reserves estimates as of December 31, 2010, 2009 and 2008. 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.

 

Estimated Reserves

 

The following table presents our estimated net proved reserves at December 31, 2010, based on our reserve report. Proved reserves are those quantities of oil and gas, which, by analysis of geo-scientific and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations and prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The data was prepared by CGA. Reserves at December 31, 2010 were determined using the unweighted arithmetic average of the first day of the month price for each month from January through December 2010. These prices were $79.43 per barrel of oil and $4.37 per Mmbtu of gas.

 

 

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on geo-scientific and engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See Item 1A. “Risk Factors — Risks Related to Our Business — Our estimated reserves are based on many assumptions that may prove to be inaccurate.” Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

At December 31, 2010, we had 13.5 Bcfe of proved undeveloped reserves. During 2010, due to liquidity constraints, we developed only 0.2 Bcfe of our proved undeveloped reserves reported in 2009 while 6.6 Bcfe was sold in 2010 in connection with the Appalachian Basin asset sale to MHR discussed above. At December 31, 2010, we did not have material proved undeveloped reserves that remain undeveloped five years subsequent to their disclosure as proved undeveloped reserves. All of our proved undeveloped reserves included in our 2010 reserve report are scheduled to be developed before 2014.

Production Volumes, Sales Prices and Production Costs

 

The following table sets forth information regarding our production properties. The production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells. All sales data excludes the effects of our derivative financial instruments, unless otherwise indicated. During the fourth quarter of 2010, we reclassified the operations and assets of our gathering system in the Cherokee Basin from our former natural gas pipelines segment to our production segment. The costs associated with our gathering system are now considered a component of our production costs. Our results presented below have been revised to reflect the reclassification.

 

 

 

 

The following tables present our production, average sales prices and production costs, excluding production and property taxes, by area for the years ended December 31, 2010 and 2009.

 

 

 

 

Producing Wells and Acreage

 

The following tables set forth information regarding our ownership of wells and total acres at December 31, 2010, 2009 and 2008. Our data for 2010 includes all wells mechanically capable of production. Our data for 2009 and 2008 includes only producing wells as we could not determine, without unreasonable effort or expense, the number of our nonproducing wells that were mechanically capable of production.

 

 

 

 

 

 

 

 

At December 31, 2010, we had 336,287 net developed and 132,590 net undeveloped acres in the Cherokee Basin and 9,426 net developed acres and 31,385 net undeveloped acres in the Appalachian Basin. Developed acres are acres spaced or assigned to productive wells/units based upon governmental authority or standard industry practice. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

 

Drilling Activities

 

Our drilling, recompletion, abandonment and acquisition activities for the periods indicated are shown below. This information includes wells in all areas in the period in which they were completed.

 

 

 

 

In addition to the activity above we drilled but did not complete eight vertical wells in the Cherokee Basin and three vertical wells in Wetzel County, West Virginia. The Wetzel County wells were sold before year end. We also had a working interest in two horizontal wells drilled in Lewis County, West Virginia. These wells were awaiting pipeline connection at the end of 2010 and were sold in January 2011.

 

Gas Gathering

 

 

Third-Party Gathering

 

We receive fees from third parties to gather their gas on our system. Excluding our royalty owners, approximately 6% of the gas transported on our gathering systems during 2010 was for third parties.

Exploration and Production

 

General

 

As the operator of wells in which we have an interest, we design and manage the development of these wells and supervise operation and maintenance activities on a day-to-day basis. We employ production and reservoir engineers, geologists and other specialists.

 

Field operations conducted by our personnel include duties performed by “pumpers” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, disposal wells and gas well flow lines). The primary equipment we own is trucks, well service rigs, stimulation assets and construction equipment. At times we utilize third-party contractors to supplement our field personnel.

 

In the Cherokee Basin, we provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third-party contractors, which typically provide these services. We believe that we are able to realize significant cost savings because we can reduce delays in executing our plan of development and avoid paying price markups. We currently rely on third-party contractors to drill our wells. Once a well is drilled, either we or a third-party contractor run the casing. We perform the cementing, fracturing and stimulation in completing our own wells. We have our own fleet of 23 well service units that we use in the process of completing our wells, and to perform remedial field operations required to maintain production from our existing wells. In the Appalachian Basin, we rely on third-party contractors for these services.

 

Leases

 

As of December 31, 2010, we had approximately 4,033 leases covering approximately 511,170 net acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount ranges from 12.5% to 18.75% resulting in an 81.25% to 87.5% net revenue interest to us.

 

Because the acquisition of oil and natural gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other operators. In order to gain the right to drill these leases, we may purchase leases from them.

 

In the Cherokee Basin, at year end, we held leases on approximately 468,878 net acres, of which 79,017 net acres are not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 16,117 net acres are scheduled to expire before December 31, 2011. If these leases expire and are not renewed, we will lose the right to develop the related properties.

 

In the Appalachian Basin, we hold oil and natural gas leases and development rights by virtue of farm-out agreements or similar mechanisms on 22,799 net acres that are still within their original lease or agreement term and are not earned or are not held by production. Unless we establish commercial production on the properties or fulfill the requirements specified by the various leases or agreements, during the prescribed time periods, these leases or agreements will expire.

 

Marketing and Major Customers

 

Production

 

During 2010, approximately 70% of our Cherokee Basin and Oklahoma gas production was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”) and approximately 82% and 18% of our oil production was sold to Sunoco Partners Marketing & Terminals L.P. and Coffeyville Refining, respectively. The ONEOK sales agreement is a monthly evergreen agreement, cancellable by either party. Prior to 2010, substantially all our gas production in the Cherokee Basin was sold to ONEOK; however, in late 2009 we diversified our gas sales in the Cherokee Basin between eight markets, including sales directly to end users. We

will seek to continue to diversify our sales portfolio balancing price, credit risk, and volume risk which is expected to reduce marketing risk and provide competition to optimize the price we receive for our production.

 

Approximately 90% of our 2010 Appalachian Basin gas production was sold to Dominion Field Services under a mix of fixed price and index based sales contracts and a market sensitive contract and 100% of our oil production in the Appalachian Basin was sold to Appalachian Oil Purchasers, a division of Clearfield Energy. The remainder was sold to various purchasers under market sensitive pricing arrangements.

 

If we were to lose any of these purchasers, we believe that we would be able to promptly replace them because we believe there are multiple options for marketing our commodities. We have discussed direct sales with refineries and industrials as well as establishing agreements with various marketing companies. The physical location of our production provides ample options for marketing the commodities to creditworthy parties.

 

Interstate Pipeline

 

The primary shipper on the KPC Pipeline in 2010 was Kansas Gas Service (“KGS”). KGS is a division of ONEOK and is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities. For 2010, approximately 76% of the revenue from the KPC Pipeline was from transportation contracts with KGS. The remaining 24% was from a mix of short-term firm transportation, interruptible transportation and park and loan contracts.

 

KGS’s contracts for firm capacity on the KPC Pipeline step down in volumes in the future. The following table presents the average volumes for the periods indicated:

 

 

Commodity Derivative Activities

 

Commodity prices were volatile in 2010 and prices for crude oil and natural gas are affected by a variety of factors beyond our control. When commodity futures prices have been at appropriate levels we have used derivative instruments to reduce commodity price uncertainty and increase cash flow predictability inherent to the marketing of our production. At this time, we believe commodity prices are not at levels that warrant actively hedging. When prices improve, we intend to resume our hedging activity. For additional information about our derivatives, see Part I, Item 1A “Risk Factors — Our hedging activities could result in financial losses or reduce our income” and Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”

 

Competition

 

Production

 

We operate in a highly competitive environment for acquiring properties, marketing our production and employing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. As a result, our competitors may be able to pay more for 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. Also, there is substantial competition for capital available for investment in our industry.

Interstate Pipeline

 

We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. In Kansas City, our major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipe Line Company. In Wichita, our major competitors include Southern Star Central Gas Pipeline, Atmos Energy Corporation and Mid-Continent Market Center.

 

Title

 

Production Properties

 

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of development operations on those properties, we conduct a title examination and perform curative work with respect to significant defects that we discover. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects that we discover on such property. We believe that we have satisfactory title to our material producing properties in accordance with standards generally accepted in our industry.

 

Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases lands over which leases have been obtained are subject to prior liens which have not been subordinated to the leases. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

 

Pipeline Rights-of-Way

 

Substantially all of our gathering systems and the KPC Pipeline are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

 

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

 

Certain of our rights to lay and maintain pipelines are derived from recorded oil and natural gas leases for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Seasonality

 

Production

 

Freezing weather and storms in the winter and flooding in the spring and summer have in the past resulted in a number of our wells being off-line for a short period of time. This adversely affects our production volumes and revenues and increases our lease operating costs due to the time spent by field employees to bring the wells back on-line. In the past this has also resulted in wells producing at lower rates for extended periods after returning to production. We have recently had success managing this exposure by using heat tape on wells and compressors to limit the amount of production that goes offline and heavy equipment to facilitate faster access to wells to return them to production after outages.

 

Interstate Pipeline

 

Due to the nature of the markets served by the KPC Pipeline, primarily the Wichita and Kansas City markets’ heating load, the utilization rate of the KPC Pipeline has traditionally been much higher in the winter months (November through March) than in the remainder of the year. As a result, KPC’s firm capacity transportation agreements have greater utilization in the winter months. KPC currently generates a disproportionate share of its revenue in the winter months.

 

Government Regulation

 

Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the federal, state and local levels by a number of federal, state and local governmental authorities under various laws and regulations governing a wide variety of matters, including allowable rates of production, plugging of abandoned wells, transportation, prevention of waste and pollution, protection of the environment and worker health and safety. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both.

 

These laws are under constant review for amendment or expansion. Moreover, the possibility exists that new legislation or regulations may be adopted. Amended, expanded or new laws and regulations increasing the regulatory burden on the crude oil and natural gas industry can have a significant impact on our operations or our customers’ ability to use natural gas and may require us or our customers to change their operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the US Environmental Protection Agency (“EPA”), the Federal Energy Regulatory Commission (“FERC”), the Bureau of Ocean Energy Management, Regulation and Enforcement, the Commodity Futures Trading Commission (“CFTC”), state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. See Part I, Item 1A. Risk Factors — “We are subject to increasing governmental regulations and environmental risks that may cause us to incur substantial cost” and “Pipeline integrity programs and repairs may impose significant costs and liabilities on us.”

 

Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies that we believe help to ensure that our operations are conducted in substantial regulatory compliance. Governmental regulations applicable to our operations include those relating to environmental matters, exploration and production activities, interstate pipeline and FERC regulations, natural gas gathering pipelines, natural gas sales, and pipeline safety.

 

Environmental Matters

 

Our operations are subject to various increasingly stringent federal, state and local laws and regulations relating to the discharge of materials into, and the protection of, the environment and imposing liability for

pollution. We have made and will continue to make expenditures in our efforts to comply with these requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with these requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the oil and gas industry, to date, we do not believe they have affected us to any greater or lesser extent than other companies in the industry. Due to the size of our operations, significant new environmental regulation could have a disproportionate adverse effect on our operations. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitation on such operations. See Part I, Item 1A Risk Factors — “We are subject to increasing governmental regulations and environmental risks that may cause us to incur substantial costs”; “We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment”; “We may face unanticipated water and other waste disposal costs”; and “Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and transportation operations.”

 

Production

 

Federal, state and local regulations apply to our exploration and production activities and impose permitting, bonding and reporting requirements. Most states, and some counties and municipalities, in which we operate also regulate the location and method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells; and/or notice to surface owners and other third parties. Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while others rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws generally prohibit venting or flaring of gas and impose requirements regarding the ratability of production. Moreover, some states impose a production or severance tax on the production and sale of oil, gas and gas liquids within its jurisdiction.

 

The Cherokee Basin has been an active producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. While the Kansas Corporation Commission’s (“KCC”) current interpretation of Kansas law is consistent with our position, it could change in the future.

 

Interstate Pipelines and FERC Regulation

 

Certain of our operations are subject to regulation by FERC. FERC regulates the terms, conditions and rates for interstate transportation and storage services, as well as various other matters relating to pipeline and storage services, operations, and construction. Our KPC Pipeline is an interstate natural gas pipeline system that is subject to FERC’s regulatory requirements. See Part I, Item 1A Risk Factors — “The KPC Pipeline is subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to recover the full cost of operating the KPC pipeline, plus a reasonable return, which may affect our business and results of operations.”

 

FERC regulates interstate natural gas pipelines pursuant to the NGA, NGPA and The Energy Policy Act of 2005 (“EP Act 2005”). FERC regulation affects the price and terms for access to natural gas pipeline

transportation. FERC is continually proposing and implementing new rules and regulations applicable to providers of interstate transportation and storage services. Under certain circumstances, these initiatives also may affect the intrastate transportation of natural gas. In October 2010, FERC issued a Notice of Inquiry seeking comment on whether and how holders of firm capacity on intrastate natural gas pipelines providing interstate transportation and storage services should be permitted to allow others to make use of their firm interstate capacity. We cannot predict the ultimate impact of these regulatory changes to our operations. We do not believe that we will be affected by any such FERC action materially differently than other industry participants with which we compete.

 

Maintaining compliance with FERC requirements on a continuing basis requires us to incur various expenses. Additional compliance expenses could be incurred if new or amended laws or regulations are enacted or existing laws or regulations are reinterpreted. In recent years, FERC has initiated various audits of pipeline compliance activities and commenced investigations of the rates charged by certain pipelines. Failure to comply with FERC regulations could subject us to penalties and fines. See Part I, Item 1A Risk Factors — “We could be subject to penalties and fines if we fail to comply with FERC regulations.”

 

Our natural gas gathering pipeline facilities are generally exempt from FERC’s jurisdiction and regulation pursuant to Section 1(b) of the NGA, which exempts pipeline facilities that perform primarily a gathering function, rather than a transportation function. However, if FERC were to determine that the facilities perform primarily a transmission function, rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities and we may be subject to fines and additional costs and regulatory burdens that would substantially increase our operating costs and would adversely affect our profitability. See Part I, Item 1A Risk Factors — “A change in the jurisdictional characterization of some of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase”

 

State Regulation of Gathering Pipelines

 

Our gathering pipeline operations are currently limited to the States of Kansas, Oklahoma, New York, and West Virginia. State regulation of gathering facilities generally includes various permitting, safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with it. We are not required to be licensed as an operator or to file reports in Oklahoma, New York or West Virginia.

 

On those portions of our gathering system that are open to third-party producers, the producers have the ability to file complaints challenging our gathering rates, terms of services and practices. We have contracts with all of the third-party producers for which we gather gas and are not aware of any complaints being filed. Our fees, terms and practices must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission (“OCC”), as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust our rates with respect to the wells subject to the complaint. We are not aware of any instance in which either the KCC or the OCC has made such a determination in the past.

 

These regulatory burdens may affect profitability, and management is unable to predict the future cost or impact of complying with such regulations. While state regulation of pipeline transportation does not materially affect our operations, we do own several small, discrete delivery laterals in Kansas that are subject to a limited jurisdiction certificate issued by the KCC. As with FERC regulation described above, state regulation of pipeline transportation may influence certain aspects of our business and the market price for our products.

 

Sales of Natural Gas

 

The price at which we buy and sell natural gas currently is not subject to federal regulation or, for the most part, state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline

transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations.

 

Interstate Pipeline Safety

 

Our pipelines are subject to regulation by the U.S. Department of Transportation (the “DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, if new or amended laws and regulations are enacted or existing laws and regulations are reinterpreted, future compliance with the NGPSA could result in increased costs.

 

Employees

 

As of December 31, 2010, we had 231 field employees in offices located in Kansas, Oklahoma, Pennsylvania, and West Virginia. We have 69 executive and administrative personnel located at our headquarters in Oklahoma City. None of our employees are covered by a collective bargaining agreement and management considers its relations with employees to be satisfactory.

 

Where To Find Additional Information

 

Additional information about us can be found on our website at www.pstr.com. Information on our website is not part of this document. We also provide free of charge on our website our filings with the SEC, including our annual reports, quarterly reports and current reports, along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

 

You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is the following:

 

 

Risks Related to Our Business

 

Energy prices are very volatile, and if commodity prices remain low or decline, our revenues, profitability and cash flows will be adversely affected. A sustained or further decline in oil and gas prices may adversely affect our business, financial condition or results of operations and our ability to fund our capital expenditures and meet our financial commitments.

 

The prices we receive for our oil and gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and gas are commodities; therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile and will likely continue to be volatile in the future. For example, during 2010, the near month NYMEX natural gas futures price ranged from a high of $6.01 per Mmbtu to a low of $3.29 per Mmbtu. As of March 1, 2011, the near month NYMEX natural gas futures price was 3.87 per Mmbtu. Approximately 98% of our production is natural gas. The prices that we receive for our production, and the levels of our production, depend on a variety of factors that are beyond our control, such as:

 

 

Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices will significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

 

 

We may be required to write-down the carrying value of our assets.

 

Lower oil and gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated reserves. Substantial decreases in oil and gas prices have had and may continue to render a significant number of our planned exploration and development projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil or gas properties, pipelines or other long-lived assets for impairments. We will be required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may therefore, require a write-down of such carrying value. For example, we recognized a ceiling test impairment of $102.9 million related to our oil and gas properties during the first quarter of 2009. We also recorded impairment charges of $53.6 million on our interstate pipeline and related contract-based intangible assets as well as $112.2 million on our gathering system assets in the fourth quarter of 2009. The impairment charge on our interstate pipeline and contract-based intangible assets was due to the loss of a significant customer during the fourth quarter of 2009. Our gathering system impairment resulted from a reduction in projected future gathering revenues anticipated with our Cherokee Basin production. The reduction in future gathering revenues was partially the result of limits imposed by our former credit facilities on our capital expenditures and consequently on our ability to further develop acreage in the Cherokee Basin, the geographic region served by our gathering system. This reduced the future projected revenues of the gathering system at that time. We may incur further impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and result in a reduction in our credit facility borrowing base.

 

We have reduced debt but we remain highly leveraged.

 

At December 31, 2010, we had $254.8 million of contractual commitments outstanding, consisting of debt service requirements and non-cancelable operating lease commitments. Of such amount, $187.0 million was outstanding under our $350 million secured borrowing base revolving credit facility with a current borrowing base of $225 million, which borrowing base may not be increased without the consent of all lenders under the facility. The borrowing base may be reduced in connection with future borrowing base redeterminations, the first of which will be effective on July 31, 2011. There has been a significant decline in oil and gas prices since the borrowing base was last determined. As a result, we currently expect the borrowing base to be reduced in connection with the redetermination as of July 31, 2011. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six monthly installments thereafter, at our election.

 

Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may create a greater risk of loss to stockholders than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our cash flow. If we do not make our debt service payments when due, our lenders may foreclose on assets securing such debt.

 

Our future level of debt could have important consequences, including the following:

 

 

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital. We may not be able to affect any of these remedies on satisfactory terms or at all.

 

Our credit agreements have substantial restrictions and financial covenants that restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our credit agreements restrict our ability to finance future operations or capital needs and to engage, expand or pursue our business activities. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions do not improve, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, our indebtedness may become immediately due and payable, the interest rates on our credit agreements may increase and the lenders’ commitment, if any, to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments in which event we may be forced to file for bankruptcy.

 

For a description of our credit facilities, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” and Note 10 in Part II, Item 8.

 

An increase in market interest rates will cause our debt service obligations to increase.

 

Borrowings under our credit agreements bear interest at floating rates. The rates are subject to adjustment based on fluctuations in market interest rates. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow. In addition, an increase in our interest expense could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

 

We may be unable to pass through all of our costs and expenses for gathering and compression to royalty owners under our gas leases, which would reduce our net income and cash flows.

 

We incur costs and expenses for gathering, dehydration, treating and compression of the gas that we produce. The terms of some of our existing gas leases and other development rights may not, and the terms of some of the gas leases and other development rights that we may acquire in the future may not, allow us to charge the full amount of these costs and expenses to the royalty owners under the leases or other agreements. On August 6, 2007, certain mineral interest owners filed a putative class action lawsuit against our wholly owned subsidiary Quest Cherokee, that, among other things, alleges Quest Cherokee improperly charged certain expenses to the mineral and/or overriding royalty interest owners under leases covering the acres leased by Quest Cherokee in Kansas. We will be responsible for any judgments or settlements with respect to this litigation. Please see Part I, Item 3 “Legal Proceedings” for a discussion of this litigation. To the extent that we are unable to charge and recover the full amount of these costs and expenses from our royalty owners, our net income and cash flows will be reduced.

We are exposed to trade credit risk in the ordinary course of our business activities.

 

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could adversely affect our results of operations and financial condition.

 

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

 

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas reserves, production and cash flow depend on our success in developing and exploiting our reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs or production from our existing wells could decline at a faster rate than we have estimated, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale.

 

Our estimated reserves are based on assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

It is not possible to measure underground accumulations of oil and gas in an exact way. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of oil and gas that cannot be directly measured and assumptions concerning future oil and gas prices, production levels and operating and development costs. In estimating our level of oil and gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

 

 

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. Additionally, there recently has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. Changing interpretations of the classification standards or disagreements with our interpretations could cause us to write-down reserves. Please read “— Future price declines may result in a write-down of our asset carrying values.”

 

Our standardized measure is calculated using unhedged oil and gas prices and is determined in accordance with the rules and regulations of the SEC. The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the market value of our estimated proved reserves. The estimated discounted future net cash flows from our estimated proved reserves is based on twelve month

average prices and current costs in effect on the day of estimate. However, actual future net cash flows from our oil and 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 gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, 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 gas industry in general.

 

Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations.

 

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as well as the market price of oil and gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

 

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We may drill

wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

 

The revenues of our interstate pipeline business are generated under contracts that must be renegotiated periodically.

 

In the past, substantially all of the revenues from the KPC Pipeline were generated under two firm capacity transportation contracts with Kansas Gas Service and one firm capacity transportation contract with Missouri Gas Energy. The contracts with KGS generated 59% and 58% of total revenues from the KPC Pipeline for the years ended December 31, 2009 and 2008, respectively, and the contract with MGE generated 32% and 38% of total revenues from the KPC Pipeline for the years ended December 31, 2009 and 2008, respectively. The MGE firm contract, which was for 46,000 Dth/d, expired on October 31, 2009, and was not renegotiated or renewed. The loss of this contract resulted in a non-cash impairment charge related to the KPC Pipeline recorded in 2009. The remaining KGS contracts generated 76% of total KPC Pipeline revenue in 2010 and volume steps down in future years.

 

If we are unable to extend or replace our firm capacity transportation contracts when they expire or renegotiate them on terms as favorable as the existing contracts, we could suffer a material reduction in revenues, earnings and cash flows. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

 

 

Our hedging activities could result in financial losses or reduce our income.

 

We have and may in the future enter into additional derivative arrangements for a significant portion of our production that could result in both realized and unrealized losses on our derivative financial instruments. The extent of our commodity price exposure is related largely to the scope of our hedging activities.

 

The prices at which we enter into derivative financial instruments covering our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current prices or the prices under our existing derivative financial instruments. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in oil and gas prices received for our future production. Conversely, our commodity price risk management strategy may limit our ability to realize cash flow from commodity price increases. Furthermore, we have a policy that requires, and our credit facilities mandate, that those derivative transactions relate to only a portion of our expected production volumes. As a result, we have direct commodity price exposure on the portion of our production volumes that is not covered by a derivative financial instrument.

 

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain

circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

 

 

Because of our lack of asset and geographic diversification, adverse developments in our operating areas would adversely affect our results of operations.

 

Substantially all of our assets are located in the Cherokee Basin. As a result, our business is disproportionately exposed to adverse developments affecting this region. Potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or this operating area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

The oil and gas industry is highly competitive and we may be unable to compete effectively with larger companies, which may adversely affect our results of operations.

 

The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and they not only drill for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our larger competitors also possess and employ financial, technical and personnel resources substantially greater than our resources. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material impact on our business activities, results of operations and financial condition.

 

With respect to the KPC Pipeline, we compete with other interstate and intrastate pipelines in the transportation of gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of gas, markets served by the pipeline, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Inc., Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipe Line Company in the Kansas City market and Southern Star Central Gas Pipeline, Inc., Atmos Energy Corporation and Mid-Continent Market Center in the Wichita market.

 

Natural gas also competes with other forms of energy available to our customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by our pipelines, such as competing or alternative forms of energy, adverse economic conditions, weather, higher fuel costs, and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

 

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

 

 

Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

 

We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. We do not have property insurance on any of our underground pipeline systems or wellheads that would cover damage to the pipelines. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Premiums and deductibles for certain insurance policies have increased substantially in recent years. Due to these cost increases, we may not be able to obtain the levels or types of insurance we would otherwise have obtained, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

 

Certain of our undeveloped acreage is subject to leases or other agreements that may expire in the near future.

 

In the Cherokee Basin, as of December 31, 2010, we held leases on approximately 468,878 net acres, of which 79,087 net acres are not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 16,117 net acres are scheduled to expire before December 31, 2011. If these leases expire and are not renewed, we will lose the right to develop the related properties.

 

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.

 

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, based on reserves at December 31, 2010, approximately 128 gross proved undeveloped drilling locations in the Cherokee Basin. These identified drilling locations represent a significant part of our future long-term development drilling program. 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. The assignment of proved reserves to these locations is based on the assumptions regarding gas prices in our December 31, 2010, reserve report. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above, our

financial condition, our ability to obtain additional capital as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, it is possible that not all of the numerous drilling locations identified will be drilled within the timeframe specified in the reserve report or will ever be drilled, and we do not know if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

 

We may incur losses as a result of title deficiencies in the properties in which we invest.

 

If an examination of the title history of a property reveals that an oil or gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such an instance, the amount paid for such lease or leases or other developed rights would be lost. It is management’s practice, in acquiring leases, or undivided interests in leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we will rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other developed rights in a specific mineral interest.

 

Prior to drilling a well, however, it is the normal practice in the industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves.

 

A change in the jurisdictional characterization of some of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.

 

Section 1(b) of the NGA exempts gas gathering facilities from FERC jurisdiction. We believe that the facilities comprising our gathering systems meet the traditional tests used by FERC to distinguish nonjurisdictional gathering facilities from jurisdictional transportation facilities, and that, as a result, our gathering systems are not subject to FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. The classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. If FERC were to determine that the facilities perform primarily a transmission function, rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities and we may be subject to fines. We believe the expenses associated with seeking certificate authority for construction, service and abandonment, establishing rates and a tariff for these other facilities, and meeting the detailed regulatory accounting and reporting requirements, if these actions were to become necessary, would substantially increase our operating costs and would adversely affect our profitability.

 

FERC regulation will still affect our gathering systems and the markets for our natural gas. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, could indirectly affect our gathering systems. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, FERC may not continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity.

 

Although natural gas gathering facilities are exempt from FERC jurisdiction under the NGA, such facilities are subject to rate regulation when owned by an interstate pipeline and other forms of regulation by

the state in which such facilities are located. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, open access requirements and rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that a number of interstate pipeline companies have transferred gathering facilities to unregulated affiliates. Our gathering operations are limited to the States of Kansas, Oklahoma and West Virginia. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with the KCC. We are not required to be licensed as an operator or to file reports in Oklahoma or West Virginia.

 

Our gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. In the future, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

Additionally, while gathering facilities and other non-interstate pipelines are generally exempt from FERC’s jurisdiction, FERC has adopted internet posting requirements that are applicable to certain gathering facilities and other non-interstate pipelines that deliver more than 50 million MMBtu on an annual basis. Our gathering facilities do not currently meet this size threshold and are, therefore, not currently subject to the posting requirements. Nevertheless, it is possible that we could become subject to the posting requirements in the future if, for example, the size threshold were to be lowered or the throughput on our gathering facilities were to increase. If we were to become subject to the posting requirements, we would likely incur additional compliance expenses.

 

The KPC Pipeline is subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to recover the full cost of operating the KPC pipeline, plus a reasonable return, which may affect our business and results of operations.

 

Rates charged by interstate natural gas pipelines may generally not exceed the just and reasonable rates approved by FERC, unless they are filed as “negotiated rates” and accepted by the FERC. In addition, interstate natural gas pipelines are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates, terms, or conditions of service. Consistent with these requirements, the rates, terms, and conditions of the natural gas transportation services provided by interstate pipelines are governed by tariffs approved by FERC.

 

We own and operate the KPC Pipeline, an interstate natural gas pipeline system that is subject to these regulatory requirements. The KPC Pipeline is a 1,120-mile interstate natural gas pipeline system, which transports natural gas from Oklahoma and western Kansas to the metropolitan markets of Wichita and Kansas City. As an interstate natural gas pipeline, the KPC Pipeline is subject to FERC’s jurisdiction and the regulatory requirements summarized above. Maintaining compliance with these requirements on a continuing basis requires us to incur various expenses. Additional compliance expenses could be incurred if new or amended laws or regulations are enacted or existing laws or regulations are reinterpreted.

 

Additionally, in recent years, FERC has initiated various audits of pipeline compliance activities and commenced investigations of the rates charged by certain pipelines. We may incur additional regulatory expenses if FERC were to commence such an audit or investigation with respect to the KPC Pipeline. The recourse rates set forth in the KPC Pipeline’s tariff could also be affected by such an investigation. Likewise, the KPC Pipeline’s customers, the state commissions that regulate certain of those customers, and other interested parties also have the right to file complaints seeking changes in the KPC Pipeline tariff, including with respect to the transportation rates stated therein.

 

As an interstate natural gas pipeline, the KPC Pipeline is subject to regulation by FERC under the NGA. FERC’s regulation of interstate natural gas pipelines extends to such matters as:

 

 

 

The KPC Pipeline may only charge transportation rates that it has been authorized to charge by FERC. In addition, FERC prohibits natural gas companies from engaging in any undue preference or discrimination with respect to rates or terms and conditions of service. The maximum recourse rates that it may charge for transportation services are established through FERC’s ratemaking process, and those recourse rates, as well as the terms and conditions of service, are set forth in the KPC Pipeline’s FERC-approved tariff. Pipelines may also negotiate rates that are higher than the maximum recourse rates stated in their tariffs, provided such rates are filed with, and approved by, FERC. Under the NGA, existing rates may be challenged by complaint or by FERC on its own initiative, and any proposed rate increases may be challenged by protest and are subject to approval by FERC. Any successful challenge against the KPC Pipeline’s current rates or any future proposed rates could adversely affect our revenues.

 

Generally and absent settlement, the maximum filed recourse rates for interstate pipelines are based on the cost of service plus an approved return on investment, the equity component of which may be determined through the use of a proxy group of similarly-situated companies. Other key determinants in the ratemaking process are debt costs, depreciation expense, operating costs of providing service, including an income tax allowance, and volume throughput and contractual capacity commitment assumptions.

 

The likely future regulations under which we will operate the KPC Pipeline may change; FERC periodically revises and refines its ratemaking and other policies in the context of rulemakings, pipeline-specific adjudications, or other regulatory proceedings. FERC’s policies may also be modified when FERC decisions are subjected to judicial review. Changes to ratemaking policies may in turn affect the rates we can charge for transportation service.

 

We could be subject to penalties and fines if we fail to comply with FERC regulations

 

EP Act 2005 gave FERC increased oversight and penalty authority relating to market manipulation and enforcement. EP Act 2005 amended the Natural Gas Act of 1938, or NGA, to prohibit market manipulation. It also amended the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC issued pursuant to those statutes to up to $1,000,000 per day, per violation. In addition, FERC has adopted regulations regarding market manipulation, which make it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact, or engage in any practice, act or course of business that operates or would operate as a fraud.

 

Given the complex and evolving nature of FERC regulation, we may incur significant costs related to compliance with FERC regulations. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation, and to order disgorgement of profits associated with any violation. FERC’s enforcement authority also includes the options of revoking or modifying existing certificate authority and referring matters to the United States Department of Justice for criminal prosecution. Since enactment of the EP Act 2005, FERC has initiated a number of enforcement proceedings and imposed penalties on various regulated entities, including other interstate natural gas pipelines.

We could be subject to regulations adopted by the Commodity Futures Trading Commission pursuant to the Dodd-Frank Act.

 

The CFTC has proposed several regulations, pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) enacted into law in July 2010, that related to the trading of derivatives, including natural gas derivatives. Given the complex and evolving nature of CFTC regulation, we may incur significant costs related to compliance with CFTC regulations, and such regulations, to the extent they apply to our activities, may affect our ability to enter into favorable transactions. We do not believe that we will be affected by any such CFTC action materially differently than other industry participants with which we compete.

 

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment.

 

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploration, development, production, gathering and transportation activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time.

 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) federal and state laws and regulations currently under development to address GHG emissions, (3) the federal Resource Conservation and Recovery Act and comparable state laws that regulate the management of waste from our facilities, 4) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties owned or operated by us or our predecessors or locations where we or our predecessors sent waste for disposal and (5) the federal Clean Water Act and the Safe Drinking Water Act and analogous state laws and regulations that impose detailed permit requirements and strict controls regarding water quality and the discharge of pollutants into waters of the United States and state waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitation on such operations. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, 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, hydrocarbons or other waste products into the environment.

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance.

 

We may face unanticipated water and other waste disposal costs.

 

We may be subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to

produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

 

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

 

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements. However, drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. These wastes may be regulated by EPA or state agencies as non-hazardous solid wastes. Moreover, it is possible that certain oil and 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 position.

 

Pipeline integrity programs and repairs may impose significant costs and liabilities on us.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The regulations require operators to:

 

 

KPC completed all baseline assessments of the covered high consequence area integrity testing in 2009 for approximately $200,000. KPC had no expenditures in 2010 to implement pipeline integrity management program testing. KPC also incurred costs of approximately $400,000 in 2009 and $30,000 in 2010 to complete

the last year of a Stray Current Survey resulting from a 2005 DOT audit. KPC plans to conduct in-line inspections on a small portion of lines in its high consequence area in order to comply with the preventive and mitigation rule from the US Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”). The in-line inspections are budgeted to cost approximately $400,000. Results of this initial inspection will help define requirements for future years. As part of the KPC Integrity Plan, KPC will begin its reassessment program of high consequence areas in 2012 with 26 miles of pipeline to be reassessed in Kansas City area and 32 miles of pipeline to be reassessed in the Wichita area. These costs may be significantly higher than what KPC has estimated or previously incurred due to the following factors:

 

 

Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and transportation operations.

 

Recent and future environmental laws and regulations, including additional federal and state restrictions on greenhouse gas emissions (“GHG”) that may be passed in response to climate change concerns, may increase our capital and operating costs and also reduce the demand for the oil and natural gas we produce. The oil and gas industry is a direct source of certain GHG emissions, such as carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. The EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule, which requires many suppliers of fossil fuels or industrial chemicals, manufacturers of vehicles and engines, and other facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to begin collecting GHG emissions data under a new reporting system as of January 1, 2010 with the first annual report due March 31, 2011. In November 2010, the EPA issued final regulations requiring the annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production (Subpart W). Although the Mandatory Reporting Rule does not control greenhouse gas emission levels from any facilities, it has still caused us to incur monitoring and reporting costs for emissions that are subject to the rule. Further, the rule’s new requirements for reporting of fugitive and vented methane emissions from the oil and gas industry can be expected to increase our monitoring and reporting costs during 2011.

 

After a series of regulatory actions finalized by EPA between December 2009 and May 2010, greenhouse gases became pollutants “subject to regulation” under the Clean Air Act’s Prevention of Significant Deterioration air quality permit program for stationary sources, and the largest of these sources have also become subject to permitting requirements under the Clean Air Act’s Title V permitting program. As a result, new major stationary sources of greenhouse gas emissions, and modifications of existing major stationary sources that significantly increase their greenhouse gas emissions will require a permit setting forth Best Available Control Technology for those emissions. EPA has, through its “Tailoring Rule,” acted to limit these permitting requirements to only the largest sources of greenhouse gas emissions initially, but these new requirements could in the future affect our operations and our ability to obtain air permits for new or modified facilities.

 

The U.S. Congress has also considered legislation to mandate reductions of greenhouse gas emissions, and at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs.

Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect the demand for our products and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have a material adverse effect on our business.

 

In addition, the U.S. Congress is currently considering certain other legislation which, if adopted in its current proposed form, could subject companies involved in oil and natural gas exploration and production activities to substantial additional regulation. If such legislation is adopted, federal tax incentives could be curtailed, and hedging activities as well as certain other business activities of exploration and production companies could be limited, resulting in increased operating costs. Any such limitations or increased capital expenditures and operating costs could have a material adverse effect on our business.

 

Our ability to grow and to increase our profitability may depend in part on our ability to make acquisitions. Acquisitions are subject to a number of risks.

 

Our ability to grow and to increase our profitability may depend in part on our ability to make acquisitions that result in an increase in our net income per share and cash flows. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations. Even if we do make acquisitions that we believe will increase our net income per share and cash flows, these acquisitions may perform below our expectations and nevertheless result in a decrease in net income and/or cash flows.

 

If third-party pipelines and other facilities interconnected to our gas pipelines become unavailable to transport or produce gas, our revenues and cash flows could be adversely affected.

 

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable to transport or produce gas, our revenues and cash flows could be adversely affected.

 

Failure of the gas that we gather on our gas gathering systems to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

 

Gas gathered on our gathering systems is delivered into interstate pipelines. These interstate pipelines establish specifications for the gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the gas delivered from our gathering systems fails to meet the specifications of a particular interstate pipeline that pipeline may refuse to accept all or a part of the gas scheduled for delivery to it. In those circumstances, we may be required to find alternative markets for that gas or to shut-in the producers of the non-conforming gas, potentially reducing our throughput volumes and revenues.

 

We do not own all of the land on which our pipelines are located or on which we may seek to locate pipelines in the future, which could disrupt our operations and growth.

 

We do not own the land on which our pipelines have been constructed, but we do have right-of-way and easement agreements from landowners and governmental agencies, some of which require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction

may subject us to more onerous terms or to increased costs if the design of a pipeline requires redirecting. Such costs could have a material adverse effect on our business, results of operations and financial condition.

 

In addition, the construction of additions to the pipelines may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to expand pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way. If the cost of obtaining new rights-of-way increases, then our business and results of operations could be adversely affected.

 

Our success depends on our key management personnel, the loss of any of whom could disrupt our business.

 

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. We have not obtained, and we do not anticipate obtaining, “key man” insurance for any of our management. The loss of services of any of our key management personnel could have a material adverse effect on our business. If the key personnel do not devote significant time and effort to the management and operation of the business, our financial results may suffer.

 

Risks Related to the Ownership of Our Common Stock

 

The price of our common stock has been and may continue to experience volatility.

 

The price of our common stock has been and may continue to be volatile. In addition to the risk factors described above, some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, sales of our common stock by significant stockholders, short-selling of our common stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition or results of operations, as well as any doubt about our ability to continue as a going concern. General market conditions and U.S. or international economic factors and political events unrelated to the performance of us may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

 

Our charter and bylaws contain provisions that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ common stock at a premium to the market price or would otherwise be beneficial to our stockholders.

 

There are provisions in our restated certificate of incorporation and bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ common stock at a premium to the market price or would otherwise be beneficial to our stockholders. For example, our restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, provisions of our restated certificate of incorporation and bylaws, including limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Delaware corporation law may also discourage takeover attempts that have not been approved by our board of directors.

 

We do not expect to pay dividends on our common stock for the foreseeable future.

 

We do not expect to pay dividends on our common stock for the foreseeable future. In addition, our credit agreements prohibit us from paying any dividends without the consent of the lenders under the applicable credit agreement, other than dividends payable solely in our equity interests.

White Deer Energy L.P. and its affiliates (“White Deer”) beneficially own approximately 70% of our common stock after giving effect to the exercise of their outstanding warrants, giving White Deer influence and control in corporate transactions and other matters, including a sale of our Company.

 

At March 1, 2011, after giving effect to the exercise of its outstanding warrants, White Deer beneficially owns 19,584,205 shares, or approximately 70%, of our common stock. In addition, we have agreed to issue White Deer additional warrants on each quarterly dividend payment date of the Series A Preferred Stock prior to July 1, 2013 on which dividends are not paid in cash but instead accrue. Until December 31, 2011, White Deer, as the holder of the Series B Preferred Stock issued with the warrants, is limited to 45% of the votes applicable to all outstanding voting stock, which limit includes any common stock held by White Deer. After December 31, 2011, the limit only restricts the voting of the Series B Preferred Stock, and White Deer may vote any shares of common stock held by it without regard to that limit.

 

As a result of its ownership, White Deer effectively will be our controlling stockholder and able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of certain corporate transactions or other matters submitted to our stockholders for approval, including, for example, potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of White Deer may not coincide with the interests of other holders of our common stock.

 

Subject to certain restrictions, White Deer may make investments in companies that compete with us. In addition, our interests may conflict with those of White Deer with respect to, among other things, business opportunities that may be presented to White Deer and to our directors associated with White Deer.

 

Substantial sales of our common stock by White Deer could cause our stock price to decline.

 

We are unable to predict whether significant amounts of our common stock will be sold by White Deer. Any sales of substantial amounts of our common stock in the public market by White Deer, or the perception that these sales might occur, could lower the market price of our common stock.

 

Forward-Looking Statements

 

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 gas properties and related pipeline infrastructure; timing and amount of future production of oil and gas; operating costs and other expenses; estimated future net revenues from oil and 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 “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” 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:

 

 

 

You should consider carefully the statements in Part I, Item 1A “Risk Factors” and other sections of this Annual Report on Form 10-K, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

 

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.

 

 

None.

 

 

We have described our properties, reserves, acreage, wells, production and drilling activity in Part I, Item 1. “Business” of this Annual Report on Form 10-K.

 

Administrative Facilities

 

The office space for the corporate headquarters for us and our subsidiaries is leased and is located at 210 Park Avenue, Oklahoma City, Oklahoma 73102. The office lease is for 10 years expiring August 31, 2017 covering approximately 35,000 square feet.

 

We own four buildings within the vicinity of Chanute, Kansas that are used for operations offices, a geological laboratory, an operations terminal and a repair facility. We own an additional building and storage yard in Lenapah, Oklahoma.

 

Through a subsidiary we lease approximately 4,744 square feet of office space located at 2200 Georgetowne Drive, Sewickley, Pennsylvania 15143. Since administrative duties have been transferred to Oklahoma City, our subsidiary has secured a sub-lease tenant for a portion the remaining term of its lease, which expires on August 1, 2013. Our subsidiary leases approximately 1,500 square feet of office space for field personnel in Harrisville, West Virginia under an annual lease expiring on August 31, 2011.

 

We have 9,801 square feet of leased office space at 3 Allen Center, 333 Clay Street, Houston, Texas 77002. This space is currently not utilized. The office lease expires on May 6, 2015.

 

We have leased facilities at Olathe, Wichita, and Medicine Lodge, Kansas for the operations of our interstate pipeline. The Olathe office consists of approximately 7,650 square feet for a lease term of five years expiring October 31, 2011. The Wichita office consists of approximately 1,240 square feet on an annual lease expiring December 31, 2011. The Medicine Lodge field office is leased on a month-to-month basis.

 

 

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We will record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably

estimated, and we will disclose the related facts in the footnotes to our financial statements, if material. If we determine that an obligation is reasonably possible, we will, if material, disclose the nature of the loss contingency and the estimated range of possible loss, or include a statement that no estimate of loss can be made. We are currently a defendant in the litigation listed below. We intend to vigorously defend the claims asserted in said litigation. We are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

 

Federal Class Action Securities Litigation

 

Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, U.S. District Court for the Western District of Oklahoma, filed September 5, 2008

 

James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison, Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008

 

J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose, Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008

 

Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

 

Four class action complaints were filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP and Quest Energy GP, LLC, the general partner of the predecessor of QELP (“QEGP”), and certain of their then current and former officers and directors as defendants. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased QRCP common stock between May 2, 2005, and August 25, 2008, and QELP common units between November 7, 2007, and August 25, 2008. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, QRCP’s stock price and the unit price of QELP were artificially inflated during the class period. On December 29, 2008, the Court consolidated these complaints. On July 9, 2010, a stipulation of settlement was filed in the consolidated federal action. On August 13, 2010, the Court entered an order preliminarily approving the settlement. On November 29, 2010, the Court approved the settlement and issued its Order and Final Judgment dismissing with prejudice all the federal individual and class securities actions as well as the federal derivative actions described herein. The settlement, however, did not become effective until the consolidated state court derivative cases were dismissed. Those derivative cases were dismissed on January 26, 2011, and the settlement became final as of that date. We contributed $1.0 million to the settlement of the lawsuits and agreed to pay approximately $400,000 representing a portion of associated defense costs of certain individual defendants. These amounts have been substantially paid as of December 31, 2010.

Federal Individual Securities Litigation

 

Bristol Capital Advisors v. Quest Resource Corporation, Inc., Jerry Cash, David E. Grose, and John Garrison, Case No. CIV-09-932, U.S. District Court for the Western District of Oklahoma, filed August 24, 2009

 

On August 24, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma naming QRCP and certain then current and former officers and directors as defendants. The complaint was filed by an individual stockholder of QRCP. The complaint asserts claims under Sections 10(b) and 20(a) of the Exchange Act. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP issued false and misleading statements and or/concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company vendor. The complaint also alleges that, as a result of these actions, QRCP’s stock price was artificially inflated when the plaintiff purchased their shares of QRCP common stock. On November 29, 2010, the action was dismissed with prejudice as part of the settlement referred to above.

 

J. Steven Emerson, Emerson Partners, J. Steven Emerson Roth IRA, J. Steven Emerson IRA RO II, and Emerson Family Foundation v. Quest Resource Corporation, Inc., Quest Energy Partners L.P., Jerry Cash, David E. Grose, and John Garrison, Case No. 5:09-cv-1226-M, U.S. District Court for the Western District of Oklahoma, filed November 3, 2009

 

On November 3, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP, and certain then current and former officers and directors as defendants. The complaint was filed by individual shareholders of QRCP stock and individual purchasers of QELP common units. The complaint asserts claims under Sections 10(b) and 20(a) of the Exchange Act. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP and QELP issued false and misleading statements and/or concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company vendor. The complaint also alleges that, as a result of these actions, the price of QRCP stock and QELP common units was artificially inflated when the plaintiffs purchased QRCP stock and QELP common units. The plaintiffs seek $10 million in damages. On November 29, 2010, the action was dismissed with prejudice as part of the settlement referred to above.

 

Federal Derivative Cases

 

James Stephens, derivatively on behalf of nominal defendant Quest Resource Corporation v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M, U.S. District Court for the Western District of Oklahoma, filed September 25, 2008

 

On September 25, 2008, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on QRCP’s behalf, which named certain of QRCP’s then current and former officers and directors as defendants. The factual allegations mirror those in the class actions described above, and the complaint asserts claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. On November 29, 2010, the action was dismissed with prejudice as part of the settlement referred to above.

William Dean Enders, derivatively on behalf of nominal defendant Quest Energy Partners, L.P. v. Jerry D. Cash, David E. Grose, David C. Lawler, Gary Pittman, Mark Stansberry, J. Philip McCormick, Douglas Brent Mueller, Mid Continent Pipe & Equipment, LLC, Reliable Pipe & Equipment, LLC, RHB Global, LLC, RHB, Inc., Rodger H. Brooks, Murrell, Hall, McIntosh & Co. PLLP, and Eide Bailly LLP, Case No. CIV-09-752-M, U.S. District Court for the Western District of Oklahoma, filed July 17, 2009

 

On July 17, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on QELP’s behalf, which named certain of its then current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks injunctive relief requiring QELP to take all necessary actions to reform and improve its corporate governance and internal procedures. On November 29, 2010, the action was dismissed with prejudice as part of the settlement referred to above.

 

State Court Derivative Cases

 

Tim Bodeker, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, Bob G. Alexander, David C. Lawler, James B. Kite, John C. Garrison, Jon H. Rateau and William H. Damon III, Case No. CJ-2008-9042, District Court of Oklahoma County, State of Oklahoma, filed October 8, 2008

 

William H. Jacobson, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G. Alexander, William H. Damon III, John C. Garrison, Murrell, Hall, McIntosh & Co., LLP, and Eide Bailly, LLP, Case No. CJ-2008-9657, District Court of Oklahoma County, State of Oklahoma, filed October 27, 2008

 

Amy Wulfert, derivatively on behalf of nominal defendant Quest Resource Corporation, v. Jerry D. Cash, David C. Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr., William H. Damon III, David E. Grose, N. Malone Mitchell III, and Bryan Simmons, Case No. CJ-2008-9042 — consolidated December 30, 2008, District Court of Oklahoma County, State of Oklahoma (Original Case No. CJ-2008-9624, filed October 24, 2008)

 

The factual allegations in these petitions mirror those in the class actions discussed above. All three petitions assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, and unjust enrichment. The Jacobson petition also asserts claims against the two auditing firms named in that suit for professional negligence and aiding and abetting the director defendants’ breaches of fiduciary duties. The Wulfert petition also asserts a claim against Mr. Bryan Simmons for aiding and abetting Mr. Cash’s and Mr. Grose’s breaches of fiduciary duties. The petitions seek damages, costs, expenses, and equitable relief. On March 26, 2009, the court consolidated these actions as In re Quest Resource Corporation Shareholder Derivative Litigation, Case No. CJ-2008-9042. In conjunction with the settlement of the securities and derivative cases, on January 26, 2011, an agreed order of dismissal was entered in the consolidated action.

 

Royalty Owner Class Action

 

Hugo Spieker, et al. v. Quest Cherokee, LLC, Case No. 07-1225-MLB, U.S. District Court for the District of Kansas, filed August 6, 2007

 

The Company was named as a defendant in a putative class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The putative class consists of all royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that the Company failed to properly make royalty payments by, among other things, paying royalties based on sale volumes rather than wellhead volumes, by allocating expenses in excess of actual costs, by improperly allocating production costs

and marketing costs to royalty owners, and by failing to pay interest on royalty payments made late. The Company has filed an answer, denying plaintiffs’ claims.

 

The parties have participated in multiple mediation sessions with the most recent in January 2011, and continue to engage in settlement discussions. The parties have agreed to a period of limited discovery with another mediation to occur thereafter. If the matter cannot be resolved at that time, the case will proceed with general discovery, a class certification hearing, and a trial on the merits. The Company has recorded an accrual of $1.0 million related to this case.

 

Litigation Related to Oil and Gas Leases

 

Billy Bob Willis, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-063, District Court of Nowata County, State of Oklahoma, filed April 28, 2009

 

Larry Reitz, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-076, District Court of Nowata County, State of Oklahoma, filed May 22, 2009

 

The above-referenced lawsuits, which were filed in April and May 2009, respectively, have been consolidated to proceed as a single action. Plaintiffs are royalty interest owners located in Nowata and Craig counties. They allege that defendants have wrongfully deducted post-production costs from the plaintiffs’ royalties and have engaged in self-dealing contracts and agreements resulting in a less than market price for the gas production. Plaintiffs seek unspecified actual and punitive damages. Limited discovery has taken place. Trial will likely occur in October, 2011. The parties have participated in settlement discussions and a mediation which was held February 25, 2011. A second mediation is scheduled for March 9, 2011.

 

 

Market Information

 

Our common stock is listed on the NASDAQ Stock Market LLC under the symbol “PSTR.” The common stock began trading on March 8, 2010, the trading day following the consummation of the Recombination. The table below presents the high and low price for each quarter since trading of our common stock began.

 

 

 

 

The closing price for our common stock on March 1, 2011 was $6.24 per share. As of March 1, 2011, there were 8,290,482 shares of common stock outstanding held of record by approximately 86 stockholders. Additionally, warrants to purchase 19,584,205 shares of our common stock at a weighted average exercise price of $3.16 per share were outstanding and held by White Deer.

 

Dividends

 

The payment of dividends on our common stock is within the discretion of the board of directors and is dependent upon many factors. We have not declared any dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future. Our credit facilities contain restrictions on our ability to pay dividends.

 

Unregistered Sales of Equity Securities

 

The information set forth in Note 12 in Part II, Item 8 of this Annual Report is incorporated herein by reference in response to this item. The additional warrants and shares of Series B preferred stock issued to White Deer were issued in reliance upon an exemption from registration pursuant to Section 4(2) under the Securities Act of 1933, as amended, which exempts transactions by an issuer not involving any public offering.

 

Issuer Purchases of Equity Securities

 

None.

 

We have derived the following selected consolidated financial information for PostRock as of and for the period ended December 31, 2010, and for our predecessor for the period from January 1 — March 5, 2010, and as of December 31, 2009 and for the years ended December 31, 2009 and 2008, from the audited consolidated financial statements of PostRock included in Part II, Item 8 of this Annual Report on Form 10-K. We have derived the selected consolidated financial information of our predecessor as of December 31, 2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 from the predecessor’s consolidated financial information included in its annual report on Form 10-K/A for the year ended December 31, 2008.

 

Comparability of information in the above table between years is affected by, among other things, (1) changes in the annual average prices for oil and natural gas, (2) increased production from drilling and development activity in 2007 and 2008 followed by a lack of development activity in 2009 due to liquidity constraints, (3) the acquisition of the KPC Pipeline on November 1, 2007, (4) the PetroEdge acquisition in July 2008, (5) investigation and litigation costs associated with the misappropriation in 2008 and 2009, (6) the Recombination in 2010 and expenses related to the Recombination in 2009 and 2010 and (7) impairment of production properties of $298.9 million in 2008 compared to $102.9 million in 2009 as well as impairment of long lived assets associated with our interstate and gathering pipelines of $165.7 million in 2009.

 

 

The following discussion should be read together with the consolidated financial statements and the notes to consolidated financial statements, which are included in Part II, Item 8 of this Annual Report on Form 10-K, and the Risk Factors, which are included in Part I, Item 1A of this Annual Report on Form 10-K.

 

Where presented in this Item 7 and Item 7A, financial information for the 2010 year includes our predecessor for the period from January 1, 2010 through March 5, 2010 and PostRock for the period from March 6, 2010 through December 31, 2010.

 

Overview of Our Company

 

We are an independent oil 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 certain other minor 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. We acquired the KPC Pipeline in November 2007.

 

Strategy

 

Our focus, particularly in the current challenging pricing environment, is on efficiently growing reserves and production, lowering costs and further reducing debt. Specifically, we are striving to become the most efficient producer in the Cherokee Basin area. 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. We are also working to increase the amount of gas being transported on our pipeline, thereby creating capacity constraints that we believe will lead to long-term firm transportation agreements. When appropriate, we intend to pursue opportunistic acquisitions that are accretive to our existing operations.

 

Financial and Operating Highlights

 

Our significant highlights in 2010 include:

 

 

 

Material Events and Transactions During 2010

 

Recombination

 

The Recombination closed on March 5, 2010. The Recombination allowed us to begin to reduce general and administrative costs and facilitated the successful restructuring of our credit facilities, allowing us to implement an enhanced development plan for our production assets. See Note 1 in Part II, Item 8 of this Annual Report on Form 10-K for further details on the Recombination.

 

White Deer Investment

 

On September 21, 2010, White Deer purchased $60 million initial liquidation preference of our Series A Cumulative Redeemable Preferred Stock and 71/2 year warrants to purchase $60 million of our common stock at an exercise price of $3.15 per share. See Liquidity and Capital Resources below and Note 12 in Part II, Item 8 of this Annual Report on Form 10-K for further details about the securities issued as a result of White Deer’s investment.

 

Credit Restructuring

 

Simultaneous with the equity investment described above, on September 21, 2010, our credit agreements were restructured and we repaid $58.9 million of our debt. The restructuring resulted in more favorable debt covenants, borrowing base provisions and interest rates for our credit facilities while permitting us to further simplify our organizational structure. See Liquidity and Capital Resources below for a description of our restructured credit facilities.

 

Appalachian Basin Asset Sale

 

In December 2010, we entered into an agreement with MHR to sell to MHR certain oil and gas properties and related assets located in Wetzel and Lewis Counties, West Virginia. The sale enabled us to reduce debt and focus on the Cherokee Basin. The sale closed in two phases for $39.7 million. The first phase covered assets located in Wetzel County which closed in December 2010 for $28 million. The second phase covered assets located in Lewis County which closed in January 2011 for $11.7 million. The amount received at both closings was paid half in cash and half in MHR common stock. See Part I. Item 1 “Business — Business Segments — Production — Appalachian Basin Asset Sale” for further details on the transaction.

 

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 (5) lease operating expense, gathering expense, interstate pipeline operating expense, and general and administrative expense.

 

General Trends and Outlook

 

Realized Prices

 

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 (“EIA”), the Henry Hub spot price averaged $4.39 per Mcf in 2010, and the forecast price averages $4.02 per Mcf in 2011 and $4.50 per Mcf in 2012. 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 2010, the discount (or basis differential) in the Cherokee Basin ranged from $(0.44)/Mmbtu to $0.05/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 “Quantitative and Qualitative Disclosures About Market Risk” 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 5.5 percent in 2010, as the economy began its recovery from the economic downturn. However, total annual natural gas consumption is forecasted to decline in 2011 as a result of fewer heating degree-days during the winter months this year as well as lower consumption in the electric power sector because of the forecast return to near-normal summer weather compared with the very warm summer last year. Driven by growth in the electric power and industrial sectors, total natural gas consumption is expected to grow by 1.6 percent in 2012 to 66.5 billion cubic feet per day (Bcf/d). Total marketed natural gas production increased significantly in 2010, by an estimated 2.4 Bcf/d, or 4.1 percent. Declines in production of 0.07 Bcf/d and 0.46 Bcf/d in Alaska and the Gulf of Mexico, respectively, were offset by a 2.9 Bcf/d increase in lower-48 onshore production. EIA expects average total production to fall by 0.3 percent in 2011 driven by a falling drilling rig count in response to lower prices. 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. The projected decline in natural gas production in 2011 and increase in natural gas consumption in 2012 are expected to contribute to a strengthening of natural gas prices late in 2011 and in 2012. As natural gas prices begin to rise, forecasted production is expected to increase by 2.2 percent in 2012.

 

EIA expects a continued tightening of world oil markets over the next two years. World oil consumption is expected to grow by an annual average of 1.5 million barrels per day (bbl/d) through 2012 while the growth in supply from non-Organization of the Petroleum Exporting Countries (non-OPEC) countries is expected to average less than 0.1 million bbl/d each year. 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 OPEC not increase production as global consumption recovers, oil prices could be significantly higher than the central forecast. 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, China’s efforts to address concerns regarding its growth and inflation rates, and unforeseen production issues. The projected WTI spot price is expected to average $93 per barrel in 2011 and $98 per barrel in 2012.

Drilling Programs

 

As a result of the global economic and financial crisis, weak commodity prices, the unauthorized transfers of funds by prior senior management and restrictions in our credit agreements, we were not able to raise the capital necessary to implement drilling programs for 2009 and most of 2010. Our liquidity constraints limited us to drilling and completing five wells in 2009 and completing 163 wells in 2010, of which 124 were drilled prior to 2010. Although the majority of our project work in the first half of the year was delivered on schedule and under budget, a number of wells did not achieve peak production rate as expected. 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 are continuing to collect data and to perform studies of this data. Based on preliminary findings, we are evaluating the possibility of finding more conventional gas reserves in other geologic zones. Individual well results from the wells drilled in the third and fourth quarter have been mixed, but on the whole these wells are meeting cumulative production targets as budgeted. We continue to further refine our understanding of the geoscience in the Cherokee Basin to improve individual well results.

 

For 2011, we have budgeted approximately $43.6 million to drill and complete 290 new wells, complete eight previously drilled wells and recomplete 40 wells in the Cherokee Basin. We intend to fund these capital expenditures with available cash from operations after taking into account our debt service obligations. 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. “Risk Factors — Risks Related to Our Business — 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.”

 

Results of Operations

 

 

 

 

Year ended December 31, 2010 compared to the year ended December 31, 2009

 

The following table presents financial and operating data for our production and pipeline segments for the fiscal years ended December 31, 2010 and 2009.

 

 

 

 

Oil and Gas Sales  Oil and gas sales increased $8.0 million, or 10.1%, to $87.9 million for the year ended December 31, 2010 from $79.9 million for the year ended December 31, 2009. An increase in average realized sales prices resulted in a $15.6 million increase in revenue while the reduction in volumes resulted in a $7.6 million decrease. Oil and gas sales exclude hedge settlements.

 

Gathering Revenue  Gathering revenue decreased $1.9 million, or 24.7%, to $5.9 million during the year ended December 31, 2010, from $7.8 million during the year ended December 31, 2009. The decrease was a result of a lower contracted transportation rate as well as lower volumes transported.

 

Pipeline Revenue  Pipeline revenue decreased $8.3 million, or 45.0%, to $10.1 million during the year ended December 31, 2010, from $18.4 million during the year ended December 31, 2009. The decrease was primarily due to the expiration of a significant firm transportation contract in October 2009.

 

Production Operating Costs  Production operating costs consist of lease operating expenses, severance and ad valorem taxes and gathering expense. Production operating costs decreased $9.0 million, or 16.1%, to $47.0 million during the year ended December 31, 2010, from $56.0 million during the year ended December 31, 2009. The decrease was due to lower ad valorem taxes of $3.0 million, lower lease operating expenses of $4.0 million and lower gathering expense of $2.6 million partially offset by an increase in severance taxes of $0.6 million. Ad valorem taxes were assessed lower during 2010 primarily due to lower prices and the lack of a drilling program during 2009 and 2010. Lease operating expenses decreased as a result of lower labor costs and lower costs for repairs and maintenance. Gathering expense was lower primarily due to lower compression costs. Production operating costs per Mcfe decreased $0.19, or 7%, to $2.39 per Mcfe during the year ended December 31, 2010, from $2.58 per Mcfe during the year ended December 31, 2009.

Pipeline Operating Expense  Pipeline operating expense was generally flat, decreasing $0.3 million, or 4.1%, to $6.3 million during the year ended December 31, 2010, from $6.6 million during the year ended December 31, 2009.

 

Production Segment Depreciation, Depletion and Amortization  We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization decreased approximately $20.1 million, or 50.8%, during the year ended December 31, 2010, to $19.4 million from $39.5 million during the year ended December 31, 2009. On a per unit basis, we had a decrease of $0.82 per Mcfe to $0.99 per Mcfe during the year ended December 31, 2010, from $1.81 per Mcfe during the year ended December 31, 2009. 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.

 

Pipeline Depreciation and Amortization  Depreciation and amortization expense decreased $4.9 million, or 58.9%, to $3.5 million during the year ended December 31, 2010, from $8.4 million during the year ended December 31, 2009. 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.

 

Production Segment Gain (loss) on Sale of Assets  Gain from the sale of assets of $13.5 million during the year ended December 31, 2010 was primarily due to the first phase of the Appalachian Basin asset sale in December 2010.

 

Impairment of Production Properties  We recorded impairments of our production properties of $215.1 million for 2009 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 Pipeline Assets  During the fourth quarter of 2009, we recorded an impairment of $53.6 million on our pipeline assets and related contract intangibles. 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  General and administrative expenses decreased $15.3 million, or 36.6%, to $26.4 million during the year ended December 31, 2010, from $41.7 million during the year ended December 31, 2009. 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. The decreases from 2009 were partly offset by federal securities lawsuits settlement costs of $1.4 million and costs to refinance our debt. See Part I, Item 3 Legal Proceedings of this Annual Report on Form 10-K for further discussion of the settlement costs.

 

Gain from Derivative Financial Instruments  Gain from derivative financial instruments increased $25.0 million to $73.1 million during the year ended December 31, 2010, from a gain of $48.1 million during the year ended December 31, 2009. 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, compared to a $50.0 million unrealized loss and a $98.1 million realized gain for the year ended December 31, 2009. 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.

Gain on Forgiveness of Debt  We recorded a gain on forgiveness of debt of $2.9 million for the year ended December 31, 2010. See “Liquidity and Capital Resources — Credit Agreements” below for a discussion of our troubled debt restructuring.

 

Interest Expense, Net  Interest expense, net, decreased $3.9 million, or 13.1%, to $25.5 million during the year ended December 31, 2010, from $29.4 million during the year ended December 31, 2009. The decrease was primarily the result of repayments of debt and lower interest rates on our restructured credit facilities.

 

Recovery of Misappropriated Funds  We recorded a recovery of misappropriated funds of $1.6 million during the year ended December 31, 2010, compared to $3.4 million during the year ended December 31, 2009. These amounts represent recoveries of funds misappropriated between 2005 and 2007 by former officers.

 

Year ended December 31, 2009 compared to the year ended December 31, 2008

 

The following table presents financial and operating data for our production and pipeline segments for the fiscal years ended December 31, 2009 and 2008.

 

 

 

 

Oil and Gas Sales  Oil and gas sales decreased $82.6 million, or 50.8%, to $79.9 million for the year ended December 31, 2009 from $162.5 million for the year ended December 31, 2008. A decrease in average realized sales prices decreased revenues by $82.5 million and a decrease in volumes resulted in an additional $0.1 million decrease. Oil and natural gas sales exclude hedge settlements.

 

Gathering Revenue  Gathering revenue decreased $0.9 million, or 10.8%, to $7.8 million during the year ended December 31, 2009, from $8.7 million during the year ended December 31, 2008. The decrease was primarily a result of lower transported volumes in the Cherokee Basin.

Pipeline Revenue  Pipeline revenue decreased $1.0 million, or 5.4%, to $18.4 million during the year ended December 31, 2009, from $19.4 million during the year ended December 31, 2008. The decrease was primarily due to the expiration of a significant firm transportation contract in October 2009 as well as a renewal of certain other contracts at lower volumes and rates.

 

Production Operating Cost  Production operating costs consist of lease operating expenses, severance and ad valorem taxes, and gathering expense. Production operating costs decreased $10.3 million, or 15.5%, to $56.0 million during the year ended December 31, 2009, from $66.3 million during the year ended December 31, 2008. This decrease was achieved through process improvement initiatives, the employment of the latest artificial lift technology in order to improve equipment reliability and minimize costly wellbore interventions and by optimizing our compression fleet to decrease fuel consumption and improve horsepower utilization. Operating cost were $2.58 per Mcfe for the year ended December 31, 2009, as compared to $3.04 per Mcfe for the year ended December 31, 2008.

 

Pipeline Operating Expense  Pipeline operating expense decreased $1.1 million, or 13.9%, to $6.6 million during the year ended December 31, 2009, from $7.7 million during the year ended December 31, 2008. The decrease was a result of our cost-cutting efforts initiated in the third quarter of 2008 and continuing through 2009.

 

Production Segment Depreciation, Depletion and Amortization  We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Included in our production segment depreciation, depletion and amortization is depreciation on our gathering system whose assets were reclassified into full cost pool in the fourth quarter of 2010. Prior to the reclassification, our gathering system assets were depreciated under the straight-line method. Our depreciation, depletion and amortization decreased approximately $20.9 million, or 34.7%, during the year ended December 31, 2009 to $39.5 million from $60.4 million during the year ended December 31, 2008. On a per unit basis, we had a decrease of $0.97 per Mcfe to $1.81 per Mcfe during the year ended December 31, 2009, from $2.78 per Mcfe during the year ended December 31, 2008. This decrease was primarily due to the impairments of our properties in the fourth quarter of 2008 and the first quarter of 2009, which decreased our rate per unit, as well as the resulting decrease in the depletable pool.

 

Pipeline Segment Depreciation and Amortization  Depreciation and amortization expense decreased $1.7 million, or 17.0%, to $8.4 million during the year ended December 31, 2009, from $10.1 million during the year ended December 31, 2008. The decrease was primarily due to a decrease in the amortization of contract related intangible assets associated with the pipeline.

 

Impairment of Production Properties  We recorded an impairment of our production properties of $102.9 million during the first quarter of 2009 as a result of a ceiling test write-down triggered by depressed prices. In addition, we recorded an impairment of long-lived assets on our gathering system of $112.2 million during the fourth quarter of 2009. 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. The impairment charges in the first and fourth quarter of 2009 totaled $215.1 million. We recorded impairments of our oil and natural gas properties of $298.9 million for 2008.

 

Impairment of Pipeline Assets  During the fourth quarter of 2009, we recorded an impairment of $53.6 million on our pipeline assets and related intangibles. The impairment was a result of the expiration of a significant firm transportation contract in October 2009, which we were unable to renew. No such impairment was required in 2008.

 

General and Administrative Expenses  General and administrative expenses increased $13.4 million, or 47.6%, to $41.7 million during the year ended December 31, 2009, from $28.3 million during the year ended December 31, 2008. The increase is primarily due to the increased legal, consulting and audit fees due to the reaudits and restatements of our financial statement as well as increased legal, investment banker, and other professional fees in connection with our recombination activities.

Gain from Derivative Financial Instruments  Gain from derivative financial instruments decreased $18.0 million to $48.1 million during the year ended December 31, 2009, from a gain of $66.1 million during the year ended December 31, 2008. 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 $72.5 million unrealized gain and a $6.3 million realized loss for the year ended December 31, 2008. The increase in realized gain included a one-time gain of $26 million as a result of amending or exiting certain above-market derivative financial instruments, in June 2009, in order to pay down debt.

 

Interest Expense, Net  Interest expense, net, increased $3.9 million, or 15.6%, to $29.3 million during the year ended December 31, 2009, from $25.4 million during the year ended December 31, 2008. The increase is primarily due to $3.5 million in write-offs of unamortized debt issuance cost associated with the modification of our credit agreements in 2009.

 

Recovery of Misappropriated Funds  As discussed above, we recorded a recovery of misappropriated funds of $3.4 million for 2009. There was no such recovery in 2008.

 

Liquidity and Capital Resources

 

Historical Cash Flows and Liquidity

 

Cash Flows from Operating Activities  Cash flows from operating activities have historically been driven by the quantities of our production and 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 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 $38.8 million for the year ended December 31, 2010, as compared to $74.6 million and $61.9 million for the years ended December 31, 2009 and 2008, respectively. The decrease from 2009 to 2010 is attributable primarily to a decrease in realized gains on our derivatives offset by a smaller decrease in accounts payable compared to the prior year. The decrease in realized derivative gain was the result of contracts with higher settlement prices and a one-time gain of $26 million in 2009 when we exited certain contracts in order to pay down debt. The increase in cash flows from operations from 2008 to 2009 is attributable primarily to an increase in realized gains on our derivatives offset by lower revenues both due to depressed oil and natural gas prices in 2009.

 

Cash Flows from Investing Activities  Cash flows from investing activities have historically been driven by sales of oil and gas properties, leasehold acquisitions, exploration and development and acquisitions of businesses. Net cash used in investing activities totaled $13.4 million for the year ended December 31, 2010, as compared to cash from investing activities of $0.3 million for the year ended December 31, 2009, and cash used of $266.6 million for the year ended December 31, 2008. Cash used in investing activities in 2010 was a result of $28.1 million of capital expenditures offset by $14.1 million in cash received primarily from the first phase of our Appalachian Basin asset sale in December 2010. Cash from investing activities was minimal in 2009 compared to prior years as we had significantly pared down our acquisition and development related capital

expenditures in response to liquidity constraints in 2009. Cash used in investing activities in 2008 of $266.6 million was primarily driven by our significant development program during that year and our acquisition of oil and gas properties in the Appalachian Basin. The following table sets forth our capital expenditures, including costs we have incurred but not paid for the periods presented.

 

 

Cash Flows from Financing Activities  Cash flows from financing activities have historically been driven by borrowing and repayments on debt instruments, issuances of common stock and the costs associated with these activities. Cash used in financing activities was $45.5 million for the year ended December 31, 2010, as compared to cash used of $67.8 million and cash provided of $211.8 million for the years ended December 31, 2009 and 2008, respectively. The cash used in 2010 was due to $102.0 million in repayments of bank borrowings and $6.5 million of debt and equity financing costs offset by $60.0 million of proceeds from the White Deer investment, discussed below, and $3.0 million of bank borrowings. The cash used in financing activities in 2009 was primarily due to debt repayment of $67.4 million and $4.7 million in debt amendment fees offset by $4.3 million in proceeds from debt. In 2008, cash was provided by an increase in borrowings of $214.2 million and proceeds from issuance of common stock of $84.8 million, partially offset by repayments of note borrowings of $59.8 million, $24.4 million of distributions to unitholders and $3.0 million in debt financing costs.

 

White Deer Investment

 

On September 21, 2010, White Deer purchased $60 million initial liquidation preference of our Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”) along with 71/2 year warrants to purchase $60 million of our common stock at an exercise price of $3.15 per share, which represents an approximate 5% premium to our closing stock price on September 1, 2010, the day before the transaction was publicly announced. The Series A Preferred Stock is entitled to a cumulative dividend of 12% per year on its liquidation preference, compounded quarterly. Prior to July 1, 2013, we can elect to pay dividends on the Series A Preferred Stock in cash. During this period, if such dividends are not paid in cash, the liquidation preference of the Series A Preferred Stock will increase by the amount of the dividend and we will issue additional warrants exercisable for a number of shares of our common stock equal to the amount of the dividend divided by the closing price of the common stock on the trading day prior to the dividend payment date. We elected not to pay cash dividends in the amount of $2.0 million that were accrued as of December 31, 2010, but instead chose to increase the liquidation preference on the Series A Preferred Stock by the same amount. Additional warrants to purchase 536,586 shares of our common stock at an exercise price of $3.69 were also issued. We are required to redeem the Series A Preferred Stock on March 21, 2018 at 100% of the liquidation preference. See Note 12 in Part II, Item 8 of this Annual Report for further details on the securities issued as a result of White Deer’s investment. At December 31, 2010, the Series A Preferred Stock had a liquidation preference of $62.0 million, and there were outstanding warrants to purchase a total of 19,584,205 shares of common stock at a weighted average exercise price of $3.16.

Appalachian Basin Asset Sale

 

On December 30, 2010, we closed the first phase of the sale of the Appalachian Basin assets to MHR for $28.0 million, consisting of $14.0 million in cash and 2.3 million shares of MHR common stock. Of the cash amount, $4.2 million was placed in escrow pursuant to the terms of the purchase agreement to cover indemnities and title defects. On January 14, 2011, we closed the second phase of the sale for $11.7 million consisting of $5.8 million in cash and 0.9 million shares of MHR common stock. Of the cash amount, $1.7 million was placed in escrow. The sale enabled us to reduce debt and focus on the Cherokee Basin. Included in the $39.7 million purchase price was approximately $36.7 million representing the purchase price of assets owned by our subsidiary, Quest Eastern Resource LLC (“QER”), pledged as collateral under the Third Amended and Restated Credit Agreement between QER, as borrower, and Royal Bank of Canada (“RBC”), as administrative and collateral agent and lender. Approximately $12.1 million of the net cash consideration and the share consideration received by QER pursuant to the purchase agreement (totaling 3.0 million shares) were paid to RBC in repayment of a portion of the term loan under that credit agreement and as consideration for the release of RBC’s liens encumbering the assets sold, which resulted in payments to RBC of $21.2 million and $9.3 million in connection with the December 2010 closing and with the January 2011 closing, respectively.

 

Credit Agreements

 

Simultaneous with the White Deer investment described above, on September 21, 2010, our credit agreements were restructured and we repaid $58.9 million of our debt. The restructuring resulted in more favorable debt covenants, borrowing base provisions and interest rates for our credit facilities while permitting us to further simplify our organizational structure.

 

Former Credit Agreements

 

Prior to the restructuring, we had the following four credit agreements:

 

(i) A term loan with an outstanding principal balance of approximately $125 million and no available capacity, secured by our assets owned by Quest Cherokee, LLC (the “Quest Cherokee Loan”);

 

(ii) A second lien senior term loan with an outstanding principal balance of approximately $30.2 million, secured by a second lien on our assets owned by Quest Cherokee, LLC (the “Second Lien Loan”);

 

(iii) A credit agreement with an outstanding principal balance of approximately $118.7 million secured by our assets owned by PostRock Midstream, LLC and Bluestem Pipeline, LLC, which included the Bluestem gas gathering system and the KPC Pipeline (the “Midstream Loan”); and

 

(iv) A credit agreement with an outstanding principal balance of approximately $43.8 million, secured by our Appalachian assets owned indirectly by PostRock Energy Services Corporation (“PESC”) (the “PESC Loan”).

 

The terms of our previous credit facilities and activity prior to the restructuring are described in Item 8. Financial Statement and Supplementary Data in our Annual Report on Form 10-K for the year ended December 31, 2009, and in Part I, Item 1 in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

 

New Credit Agreements

 

As a result of the restructuring of our credit facilities, we now have the following three credit agreements (the “New Credit Agreements”):

 

(i) A $350 million secured borrowing base revolving credit facility with an initial borrowing base of $225 million and outstanding borrowings of $187.0 million at December 31, 2010, secured by, among other things, a first lien on our Cherokee Basin exploration and production assets, certain producing Appalachian production assets and the Cherokee Basin gas gathering system and a second lien on our interstate natural gas transportation pipeline (the “Borrowing Base Facility”);

 

(ii) A term loan with a balance of $13.5 million at December 31, 2010, secured by, among other things, a first lien on our interstate natural gas transportation pipeline and a second lien on our Cherokee

Basin exploration and production assets, certain producing Appalachian production assets and the Cherokee Basin gas gathering system (the “Secured Pipeline Loan”); and

 

(iii) A term loan with a carrying amount of $19.7 million at December 31, 2010, secured by our assets owned by QER, which include certain producing and non-producing Appalachian properties and the Appalachian gas gathering system, and a pledge of the equity of QER (the “QER Loan”).

 

Borrowing Base Facility

 

The Borrowing Base Facility with PESC and our subsidiary PostRock MidContinent Production, LLC (“PMP”), as borrowers, RBC as administrative and collateral agent, and the lenders party thereto is a secured borrowing base facility with an initial borrowing base of $225 million and is guaranteed by PostRock and certain of its subsidiaries.

 

Under the terms of the Borrowing Base Facility, PMP and PESC prepaid the outstanding indebtedness under the Quest Cherokee Loan in an amount equal to approximately $19.2 million. In consideration therefor, the lenders completely restructured the credit agreements relating to the Quest Cherokee Loan and the Second Lien Loan with the Borrowing Base Facility, partially restructured the Midstream Loan, and secured the Borrowing Base Facility with the same assets that secured the Quest Cherokee Credit Agreement and the Second Lien Loan Agreement (including the assets of PMP, which include all of the oil and natural gas exploration assets located in the Cherokee Basin and all of the oil and natural gas exploration assets located in the Appalachian basin that are not owned by QER) in addition to the Bluestem gathering pipeline system (which had formerly partially secured the Midstream Loan). See Note 10 in Part II, Item 8 in this Annual Report on Form 10-K for a summary of the material terms of the Borrowing Base Facility.

 

At March 1, 2011, the outstanding balance on the Borrowing Base Facility was $181.5 million with an additional $1.5 million in outstanding letters of credit, resulting in approximately $42.0 million of additional availability.

 

Secured Pipeline Loan

 

The Secured Pipeline Loan with PESC and PostRock KPC Pipeline, LLC (“KPC”) as borrowers, RBC as administrative and collateral agent, and the lenders party thereto is a $15 million term loan secured by a first lien on the KPC Pipeline and the other assets of KPC, and by a second lien on the assets on which the lenders under the Borrowing Base Facility have a first lien.

 

Under the terms of the Secured Pipeline Loan, PESC and KPC prepaid approximately $14.7 million of the outstanding indebtedness under the Midstream Loan in exchange for the assignment by the lenders under the Midstream Loan of approximately $89.0 million of the indebtedness owing under the Midstream Loan to the lenders under the Borrowing Base Facility. The remaining $15.0 million of such indebtedness was retained under the Secured Pipeline Loan. See Note 10 in Part II, Item 8 of this Annual Report on Form 10-K for a summary of the material terms of the Secured Pipeline Loan.

 

At March 1, 2011, the outstanding balance on the Secured Pipeline Loan was $12.5 million. A monthly installment payment of $500,000 is due in late March followed by 12 additional payments of $1.0 million each due monthly thereafter.

 

QER Loan

 

As part of the closing of our amended and restated credit facilities, PESC, QER and RBC entered into an assumption agreement whereby QER assumed all of PESC’s rights and obligations as borrower under the PESC Loan. In addition, QER, as borrower, entered into the third amended and restated credit agreement with RBC in the amount of approximately $43.8 million. In connection therewith, RBC, the lender under the PESC Loan released PESC from any liability or obligation to repay amounts owing under the PESC Loan and all of the guarantors thereunder from their respective guarantees of the indebtedness owing under the PESC Loan and (except for QER) from their respective mortgages and security agreements. RBC also released the liens on all the collateral owned by PESC, other than the Appalachian assets owned by QER and the equity of QER;

and agreed to reconvey the overriding royalty interests to their respective grantors (or their designees) at such time as the Appalachian assets or equity of QER are sold or all outstanding obligations under the credit agreement have been paid in full or otherwise deemed to have been satisfied. Accordingly, under the QER Loan, RBC has recourse only to QER, its assets and the equity of QER. See Note 10 in Part II, Item 8 of this Annual Report on Form 10-K for a summary of the material terms of the QER Loan.

 

On February 21, 2011, we amended the QER Loan to delay the date of the first interest payment. No interest payments are due prior to May 16, 2011. Subsequent to May 16, 2011, interest payments on LIBOR loans are due on the last day of each LIBOR interest period, in no event less than quarterly, and interest payments on Base Rate Loans are due at the end of each quarter, beginning June 30, 2011.

 

At March 1, 2010, the carrying amount on the QER Loan was $10.4 million with no additional availability.

 

In connection with the QER Loan, we entered into an asset sale agreement with RBC that allowed us to sell QER or its assets and, in the event the proceeds are not adequate to repay the QER Loan in full, we agreed to pay a portion of such shortfall in cash, stock or a combination thereof. As discussed under “— Appalachian Basin Asset Sale” above, we received $36.7 million in gross proceeds on the sale of QER’s assets pledged as collateral under the QER Loan and made repayments to RBC totaling $30.5 million in cash and MHR common stock. Approximately $5.4 million of cash consideration received on the sale of QER’s assets at the first two closings have been placed in escrow pursuant to the purchase agreement to cover indemnities and title defects. The extent of indemnities or title defects would determine the amount of escrowed funds reconveyed back to MHR. Any remaining balance of escrowed funds upon termination of the escrow will be remitted to RBC or PostRock pursuant to the terms of the asset sale agreement between the parties.

 

The restructuring which resulted in the QER Loan is considered a “troubled debt restructuring” under accounting guidance. In accordance with the guidance, we evaluated the maximum possible future cash flows conveyable to RBC in satisfaction of the QER Loan. In evaluating future cash proceeds to RBC, we considered our proceeds already received from the sale of our Appalachian Basin assets to MHR, the remaining provisions under the purchase agreement governing the Appalachian Basin asset sale and estimated fees related to the sale. As our estimate of future cash flows was less than the principal value of the QER Loan, we reduced the carrying amount of the QER Loan by $2.9 million while recording a corresponding gain on troubled debt restructuring during the fourth quarter of 2010. Absent this reduction, the outstanding principal balance on the QER Loan was $22.6 million at December 31, 2010. See Note 10 in Part II, Item 8 of this Annual Report on Form 10-K for a discussion on the accounting provisions for troubled debt restructurings.

 

Sources of Liquidity in 2011 and Capital Requirements

 

We rely on our cash flows from operating activities as a source of internally generated liquidity. For the most recent two 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 ability to control operating expenses. We generated cash of $32 million and $98 million from settlements of our oil and gas derivatives during 2010 and 2009, respectively. During this time, our derivative contracts covered approximately 83% and 72% of our production in 2010 and 2009. The volume covered by outstanding contracts as a percentage of our current year production is 70% in 2011, 57% in 2012 and 46% in 2013. At this time, we believe that commodity prices are not at levels that warrant actively hedging. When prices improve, we intend to resume our hedging activity. To a lesser extent, we also rely on sale of our non-core production assets to internally generate liquidity. As discussed above, the sale of our Appalachia basin assets generated $28.0 million and $11.7 million in proceeds in December 2010 and January 2011, respectively.

 

Our liquidity has improved substantially since restructuring our debt and completing the White Deer investment. At March 1, 2011, we have $42.0 million of availability under our Borrowing Base Facility which we utilize as an external source of long and short term liquidity. An additional $30 million of additional capital