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EX-23.1 - EX-23.1 - PostRock Energy Corph69920exv23w1.htm
EX-21.1 - EX-21.1 - PostRock Energy Corph69920exv21w1.htm
EX-99.1 - EX-99.1 - PostRock Energy Corph69920exv99w1.htm
EX-32.1 - EX-32.1 - PostRock Energy Corph69920exv32w1.htm
EX-31.1 - EX-31.1 - PostRock Energy Corph69920exv31w1.htm
Table of Contents

 
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, 2009
 
Commission file number: 001-34635
PostRock Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
 
     
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  27-0981065
(I.R.S. Employer
Identification No.)
210 Park Avenue, Suite 2750
Oklahoma City, Oklahoma
(Address of Principal Executive Offices)
  73102
(Zip Code)
 
Registrant’s telephone number, including area code:
(405) 600-7704
 
Securities Registered Pursuant to Section 12(b) of the Exchange Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock, par value $0.01 per share   The NASDAQ Stock Market LLC
 
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.  þ
 
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):
 
Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(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
 
PostRock Energy Corporation became a publicly traded corporation upon consummation of the recombination of Quest Resource Corporation, Quest Energy Partners, L.P. and Quest Midstream Partners, L.P. on March 5, 2010. Accordingly, the registrant did not have an aggregate market value of its common stock as of the last business day of June 30, 2009. As of March 8, 2010, there were 8,029,898 shares of common stock of PostRock Energy Corporation outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
None.
 


 

 
TABLE OF CONTENTS
 
                 
PART I
  ITEM 1.     BUSINESS     1  
  ITEM 1A.     RISK FACTORS     36  
  ITEM 1B.     UNRESOLVED STAFF COMMENTS     60  
  ITEM 2.     PROPERTIES     60  
  ITEM 3.     LEGAL PROCEEDINGS     60  
 
PART II
  ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES     65  
  ITEM 6.     SELECTED FINANCIAL DATA (PREDECESSOR)     66  
  ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     67  
  ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     90  
  ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     91  
  ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     91  
  ITEM 9A(T).     CONTROLS AND PROCEDURES     91  
  ITEM 9B.     OTHER INFORMATION     94  
 
PART III
  ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE     95  
  ITEM 11.     EXECUTIVE COMPENSATION     95  
  ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS     95  
  ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE     95  
  ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES     95  
 
PART IV
  ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES     95  
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1


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PART I
 
ITEM 1.   BUSINESS.
 
General
 
PostRock Energy Corporation (“PostRock”) is a Delaware corporation formed on July 1, 2009 for the purpose of effecting the recombination of Quest Resource Corporation (now named PostRock Energy Services Corporation) (“QRCP”), Quest Energy Partners, L.P. (now named PostRock MidContinent Production, LLC) (“QELP”) and Quest Midstream Partners, L.P. (now named PostRock Midstream, LLC) (“QMLP”). On July 2, 2009, PostRock, QRCP, QELP, QMLP and other parties thereto entered into a merger agreement pursuant to which QRCP, QELP and QMLP would recombine. The recombination was effected by forming a new publicly traded corporation, subsequently named PostRock, that, through a series of mergers and entity conversions, wholly owns all three entities. The recombination was completed on March 5, 2010. PostRock has no significant assets other than the stock or other voting securities of its subsidiaries. Immediately upon completion of the recombination, PostRock’s equity was owned approximately 44% by former QMLP common unit holders, approximately 33% by former QELP common unitholders (other than QRCP), and approximately 23% by former QRCP stockholders.
 
Our principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 600-7704.
 
In this Annual Report on Form 10-K, unless the context requires otherwise, references to “we,” “us” and “our” with respect to periods before the completion of the recombination refer to the business and operations of QRCP, QELP and QMLP and their subsidiaries on a consolidated basis, and references to “PostRock,” “we,” “us” and “our” with respect to periods after the completion of the recombination refer to PostRock and its consolidated subsidiaries.
 
We are an integrated independent energy company engaged in the acquisition, exploration, development, production and transportation of oil and natural gas.
 
We divide our operations into two reportable business segments:
 
  •  Oil and natural gas production; and
 
  •  Natural gas pipelines, including transporting, gathering, treating and processing natural gas.
 
Financial information by segment and revenues from our external customers are located in Part  I, Item 8. “Financial Statements and Supplementary Data” to this Annual Report on Form 10-K.
 
Our assets as of December 31, 2009 consisted of the following:
 
  •  Cherokee Basin:  Approximately 2,849 gross wells, which includes oil, natural gas and service wells, the development rights to approximately 516,184 net acres and approximately 2,173 miles of gas gathering pipeline in the Cherokee Basin. Of the 2,849 wells, there are approximately 189 wells that we believe to be capable of producing should gathering infrastructure be available. Of these 189 wells, approximately 100 wells are in an area where we have partially completed this infrastructure. Under Securities Exchange Commission (“SEC”) criteria, the estimated net proved reserves associated with these assets as of December 31, 2009 were 51.9 Bcfe. Based on NYMEX forward pricing as of February 1, 2010 and lower transportation costs as described under “Oil and Gas Data — Sensitivity of Reserves to Prices and Costs,” the estimated net proved reserves were 192.2 Bcfe.
 
  •  Appalachian Basin:  Approximately 498 gross gas wells, the development rights to approximately 44,507 net acres and approximately 183 miles of gas gathering pipeline in the Appalachian Basin. Under SEC criteria, the estimated net proved reserves associated with these assets as of December 31, 2009 were 18.9 Bcfe. Based on NYMEX forward pricing as of February 1, 2010 and lower transportation costs as described under “Oil and Gas Data — Sensitivity of Reserves to Prices and Costs,” the estimated net proved reserves were 26.3 Bcfe.


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  •  Central Oklahoma:  Approximately 65 gross wells, which includes oil, natural gas and service wells, and the development rights to approximately 1,480 net acres in Seminole County, Oklahoma. Under SEC criteria, the estimated net proved reserves associated with these Oklahoma properties as of December 31, 2009 were 3.9 Bcfe. Based on NYMEX forward pricing as of February 1, 2010 and lower transportation costs as described under “Oil and Gas Data — Sensitivity of Reserves to Prices and Costs,” the estimated net proved reserves were 4.3 Bcfe.
 
  •  Interstate Pipeline:  An 1,120 mile interstate natural gas pipeline that transports natural gas from northern Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets.
 
Oil and Gas Production
 
Cherokee Basin.  Our oil and gas production operations are primarily focused on the development of coal bed methane (“CBM”) in a 15-county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2009, we had approximately 51.9 Bcfe of estimated net proved reserves in the Cherokee Basin. We operate approximately 99% of the existing Cherokee Basin wells and have an average net working interest of approximately 99% and an average net revenue interest of approximately 82% in those wells. We believe we are the largest producer of natural gas in the Cherokee Basin based on our average net daily production of 55.3 Mmcfe for the year ended December 31, 2009.
 
A typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years. As of December 31, 2009, we had the development rights to approximately 516,184 net acres throughout the Cherokee Basin, with 34.5% of those acres undeveloped, and were operating approximately 2,849 gross wells in the Cherokee Basin.
 
For 2010, we have budgeted approximately $6.0 million to complete and $5.5 million to connect 108 gross wells that were previously drilled but not completed and $2.7 million for land and equipment in the Cherokee Basin. We intend to fund these capital expenditures with available cash from operations after taking into account our debt service obligations and with the proceeds of additional equity capital issuances and borrowings, but there can be no assurance that we will be able to obtain the funds to achieve this plan.
 
Appalachian Basin.  Our oil and gas production operations in the Appalachian Basin are primarily focused on the development of the Marcellus Shale. Our properties in this region were purchased in July 2008 through the acquisition of privately held PetroEdge Resources (WV) LLC (“PetroEdge”) for approximately $142 million in cash. We have identified, based on reserves as of December 31, 2009, approximately 25 gross proved undeveloped drilling locations and approximately 415 additional gross potential drilling locations in the Appalachian Basin, which consist of approximately 331 potential gross vertical well locations and approximately 84 potential gross horizontal well locations, including significant development opportunities for Devonian Sands and Brown Shales. These potential well locations are located within our acreage in West Virginia and New York and 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 twelve-month average price assumptions in our December 31, 2009 reserve report. In addition, no proved reserves are assigned to any of the approximately 415 Appalachian Basin potential drilling locations we have identified and therefore, there exists greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. For 2010, we have budgeted approximately $20 million of net expenditures to drill and complete three vertical wells and six horizontal wells and $2.5 million on land, equipment and connections in the Appalachian Basin. There can be no assurance that we will be able to obtain the capital necessary to achieve this plan.
 
As of December 31, 2009, our properties in the Appalachian Basin consisted of:
 
  •  approximately 44,507 net acres of oil and natural gas producing properties with estimated proved reserves of 18.9 Bcfe, which are approximately 60% proved developed, and net production of approximately 2.9 Mmcfe/d; and
 
  •  Approximately 498 gross wells.


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We operate approximately 99% of the existing wells and have an average net working interest of approximately 93% and an average net revenue interest of approximately 74%. Our average net daily production in the Appalachian Basin was approximately 2.9 Mmcfe for 2009. Typical horizontal Marcellus Shale wells have a predictable production profile and an estimated productive life of approximately 50 years.
 
As of December 31, 2009, we owned the development rights to approximately 44,507 net acres throughout the Appalachian Basin, with 78% of that acreage undeveloped.
 
Central Oklahoma Oil Properties.  As of December 31, 2009, we owned 65 gross wells, which include oil, natural gas and service wells, and the development rights to approximately 1,480 net acres in Central Oklahoma and our oil producing properties in Central Oklahoma had estimated net proved reserves, as of December 31, 2009, of 3.9 Bcfe, all of which were proved developed producing. During 2009, net production for our Central Oklahoma properties was approximately 148 Bbls/d. Our oil production operations in Central Oklahoma are expected to be primarily focused on the development of the Hunton Formation. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approval, oil prices, costs and drilling results.
 
Natural Gas Pipelines
 
Cherokee Basin.  We own and operate a natural gas gathering pipeline network of approximately 2,173 miles that serves our acreage position in the Cherokee Basin. As of December 31, 2009, this system had a maximum daily throughput of approximately 85 Mmcf/d. We transport 99% of our Cherokee Basin gas production on our gas gathering pipeline network to interstate pipeline delivery points. As of December 31, 2009, we had an inventory of approximately 189 gross drilled CBM wells awaiting connection to our gas gathering system.
 
Appalachian Basin.  We own and operate a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline network delivers both to intrastate gathering and interstate pipeline delivery points. As of December 31, 2009, this system had a maximum daily throughput of approximately 18.0 Mmcf/d. All of our Appalachian Basin gas production is transported by this gas gathering pipeline network.
 
Interstate Pipeline System.  Our interstate pipeline operations consist of a 1,120 mile interstate natural gas pipeline (the “KPC Pipeline”), which transports natural gas from northern Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. The pipeline was purchased in November 2007 for approximately $133.7 million in cash, which was financed with funds from an equity issuance and from $58 million in borrowings. It is one of only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC Pipeline includes three compressor stations with a total of 14,680 horsepower and has a throughput capacity of approximately 160 Mmcf/d. The Federal Energy Regulatory Commission (“FERC”) regulates the KPC Pipeline. The KPC Pipeline also has supply interconnections with pipelines owned and/or operated by Enogex Inc., Panhandle Eastern PipeLine Company and ANR Pipeline Company, which enable us to transport natural gas volumes sourced from the Anadarko and Arkoma Basins, as well as the western Kansas and Oklahoma panhandle producing regions.
 
Competitive Strengths
 
Dominant Position in the Cherokee Basin
 
We believe we are the largest producer of natural gas in the Cherokee Basin. During 2009, our net natural gas production in the basin was 55.3 Mmcf/d of natural gas. Our assets include a 99% working interest in 2,849 wells on 516,184 net acres in the Cherokee Basin. Based on NYMEX forward pricing as of February 1, 2010 and lower transportation costs as described under “Oil and Gas Data — Sensitivity of Reserves to Prices and Costs,” we had 192.2 Bcfe of proved reserves in the Cherokee Basin as of December 31, 2009.
 
The Cherokee Basin is one of the largest CBM fields in the United States, generally characterized by having smaller wells with lower production per well and, thus, higher per unit costs than other conventional and unconventional natural gas plays. We believe that our size and relative position in the region is particularly


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valuable as we are able to maintain economies of scale that facilitate higher returns than those earned by our competitors and a stronger negotiating position on mineral leases, premium equipment and services. In addition, our dominant position makes us the logical consolidator of assets in the region.
 
Attractive Underlying Economics
 
Although the CBM wells in the Cherokee Basin are small by comparison to other conventional and non-conventional natural gas plays, we believe the underlying economics are consistent with other fields in the industry. We estimate that for 2010, our average cost for drilling and completing a well will be between $110,000 and $125,000 excluding the related pipeline infrastructure, or approximately $170,000 including the related pipeline infrastructure. We achieve these low costs because we drill to relatively shallow coal seams and can build a well in one to two days. We also own and operate fracture treatment equipment in the Cherokee Basin, which we believe allows us to complete our wells for a lower cost than our peers that rely upon third-party service providers. During a recent major drilling and completion program, which ended in the third quarter of 2008, we added net reserves of approximately 110 Mmcfe per well, resulting in a finding and development cost which we believe is competitive in the industry.
 
Integrated Business Model
 
Due to smaller well sizes in the Cherokee Basin, the rate of return we can achieve is highly sensitive to both our drilling costs and our operational costs. As a result, we have developed an integrated business model to drive our operations in an efficient and cost effective manner. In addition, due to its somewhat remote location and low capital expenditure requirements relative to more prolific basins, there are not currently enough service providers of sufficient scale and expertise to service the Cherokee Basin. To mitigate this, we have developed our own fleet of equipment and the expertise to use it in the field. In developing our assets, we tightly control the process of fracing and completing our wells by utilizing our two hydraulic frac units and our five cementing units. Once drilled, we are able to efficiently maintain our wells with our fleet of 24 workover units. Controlling these processes helps us to efficiently deploy our capital.
 
In 2008, which is the last year during which we actively developed the basin, we were able to drill 338 wells in eight months, roughly four months ahead of schedule and $10 million under budget. Utilizing our well servicing fleet and state of the art SCADA well pumping software, we have focused on keeping as many of our wells online as possible, and as of December 31, 2009, 99.7% of our producing wells were online producing CBM. Over the past three years, we have developed an artificial lift technology specifically suited for our wells in the Cherokee Basin that significantly improves well productivity. By reducing workover costs, decreasing offline wells, and increasing well productivity with artificial lift technology, we were able to reduce our total oil and natural gas production costs (excluding production and property taxes) from $1.58 per Mcfe in 2008 to $1.19 per Mcfe in 2009, a 25% decrease.
 
Extensive Midstream Infrastructure
 
Consistent with our goal to control costs through an integrated strategy, we have a well developed midstream infrastructure and a sophisticated gas marketing operation designed to reduce our transportation costs and to achieve the highest possible price for our gas. In the Cherokee Basin, we have 2,173 miles of gathering pipeline with 85 Mmcfe/d of throughput capacity. By owning this infrastructure, we reduce our costs by approximately 24% of market revenue, equivalent to the rate we charge third parties to use our pipelines. Today, we deliver 100% of our natural gas to the Southern Star pipeline and receive Southern Star’s posted price plus a producing zone premium. We are in the process of connecting our gathering system to the KPC Pipeline, and when complete, we intend to market the KPC Pipeline as a header system, allowing greater opportunities to sell our natural gas to different markets, via the ANR, Panhandle Eastern, Kinder Morgan and Rockies Express pipelines. By creating access to premium markets in the upper Midwest and the Northeast, we believe connecting KPC to PostRock’s existing production will allow us to receive a premium price for our gas or mitigate a regional differential we might otherwise be required to accept on Southern Star.


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Stable Base Production
 
The Cherokee Basin is a relatively mature field, and we believe our 2,849 wells are on a low and stable decline curve. Our daily net production in the third quarter of 2008 was 59 Mmcfe/d. We have not connected any new wells since then, and have elected to defer production on approximately 600 wells due to low natural gas prices. In the fourth quarter of 2009, our production had declined to 52 Mmcfe/d, which equates to an annualized decline rate of approximately 10%. In 2010, as we resume development activities, we expect that the decline will reverse and that our production will grow. Unlike companies that have a steeper decline rate and rely more heavily on development activities to replace their production, we believe we have a competitive advantage because we can hedge a significant portion of our stable production base, enabling us to lock in baseline cash flows to service our debt and further develop our assets.
 
Strong Commodity Hedging Position
 
As of December 31, 2009, we had 76% of our expected proved developed producing production for the next four years hedged at an average net price to us of $6.37 per Mmbtu. This hedge position includes both fixed price swaps based on NYMEX or Southern Star prices and basis differential swaps between NYMEX and various Southern Star delivery locations. This hedge position is expected to provide us approximately $317 million of revenues over the next four years, even if the remainder of our production is sold at break-even gas prices.
 
Valuable Appalachian Acreage Position
 
In July 2008, we entered the Appalachian Basin through our purchase of PetroEdge Resources. As a result of this acquisition, we now own a small amount of existing conventional production and 44,507 Marcellus Shale acres, including 8,514 acres in Wetzel and Lewis Counties in West Virginia. We have chosen to focus on areas with existing infrastructure, substantially lowering the cost of developing these assets. We have identified 84 horizontal well locations on our acreage in Wetzel and Lewis counties. Based on NYMEX forward pricing as of February 1, 2010 and lower transportation costs as described under “Oil and Gas Data — Sensitivity of Reserves to Prices and Costs,” we had 26.3 Bcfe of proved reserves in the Appalachian Basin.
 
Business Strategies
 
Improve Financial Flexibility
 
We are focused on improving our financial flexibility by strengthening our leverage profile and enhancing liquidity. We are committed to issuing equity for the purpose of both repaying debt and acquiring additional producing acreage in the Cherokee Basin. We also intend to redeploy our free cash flow from operations into our assets to help grow our reserves and production, which will allow us to further improve our leverage profile over time.
 
Continued Development of the Cherokee Basin Through Strict and Systematic Operational Controls
 
As we develop our economical drilling locations in the Cherokee Basin, we will continue to utilize our integrated model to drive efficiency and minimize costs. We will focus our drilling, completion, maintenance, and marketing operations on industry best practices and continued technological enhancements to maximize our return on assets and capital deployed.
 
Actively Manage Price Exposure through Midstream Strategy and Hedging
 
We intend to actively manage our exposure to natural gas prices and basis differential in the MidContinent region by connecting our gathering system to the KPC Pipeline. By creating access to premium markets in the upper Midwest and the Northeast, we believe connecting KPC to PostRock’s existing production will allow us to receive a premium price for our gas or mitigate a regional differential we might


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otherwise receive on Southern Star. Once this connection is complete, we expect to be in a position to significantly expand the markets where our gas can be sold, thus reducing our exposure to the historically volatile basis differentials between NYMEX and the Southern Star delivery points. Further, we intend to continue to use both NYMEX swaps and basis swaps to protect the price at which we sell gas. By maximizing the revenue we earn for our gas, and locking in attractive prices when available, we believe we can stabilize and significantly increase our cash flow generation.
 
Consolidate the Cherokee Basin
 
To further enhance our economies of scale, we intend to actively pursue acquisitions in the Cherokee Basin. Consistent with our strategy to improve our financial flexibility, we intend to make acquisitions utilizing our equity. We believe our integrated model, midstream footprint and gas marketing capabilities are unique to the Cherokee Basin, and make our competitors’ gas more valuable under our control. We believe that we offer a compelling value proposition for other producers in the region.
 
Develop Appalachian Assets
 
We have approximately 25 gross proved undeveloped drilling locations and an additional 415 potential locations on approximately 45,000 acres in the Marcellus Shale. We intend to prudently develop this acreage position by redeploying cash flow generated in the Cherokee Basin. As we are focused on locations in areas with existing infrastructure, we expect our development plan to have a near-term material impact on our proved reserves and production. We believe investing in this area is the most expedient way for us to improve our financial flexibility and return on capital.
 
Description of Our Exploration and Production Properties and Projects
 
Cherokee Basin
 
We produce CBM gas out of our properties located in the Cherokee Basin. The Cherokee Basin is located in southeastern Kansas and northeastern Oklahoma. 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 coal seams we target for development are found at depths of 300 to 1,400 feet. 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.
 
The rock containing conventional gas, referred to as “source rock,” is usually different from reservoir rock, which is the rock through which the conventional gas is produced, while in CBM, 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 allows large quantities of gas to be stored at relatively low pressures. A 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 depressuring before desorption can occur and the methane begins to flow at commercial rates. Our Cherokee Basin CBM properties typically dewater for a period of 12 months before peak production rates are achieved.


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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. Once coal bed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional gas. The CBM produced from our Cherokee Basin properties has an Mmbtu content of approximately 970 Mmbtu, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050-1,300 Mmbtus.
 
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. 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 and a slurry of fluid and sand is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.
 
Cherokee Basin Projects
 
We intend to develop our CBM reserves in the Cherokee Basin on both 160-acre and 80-acre spacing. Our wells generally reach total depth in 1.5 days. During 2009, we drilled and completed one well. During a recent major drilling and completion program, which ended in the third quarter of 2008, our cost to drill and complete a well, excluding the related pipeline infrastructure, was approximately $125,000. We estimate that for 2010, our average cost for drilling and completing a well will be between $110,000 and $125,000 excluding the related pipeline infrastructure, or approximately $170,000 including the related pipeline infrastructure. For 2010, in the Cherokee Basin, we have budgeted approximately $6.0 million to complete and $5.5 million to connect 108 gross wells that were previously drilled but not completed. The majority of these new wells will be completed on locations that are classified as containing proved reserves in the December 31, 2009 reserve report. In 2010, we have budgeted an additional $2.7 million for land and equipment. However, we intend to fund these capital expenditures only to the extent that we have available cash from operations after taking into account our debt service and other obligations, and with the proceeds of equity capital issuances and borrowings. We can give no assurance that any such funds will be available.
 
We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has net reserves of approximately 110 Mmcf. Our general production profile for a CBM well averages an initial production rate of 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered. A period of relatively flat production of 50-55 Mcf/d (net) follows the initial dewatering period for approximately twelve months. Thereafter, production begins to decline. The standard economic life is approximately 15 years. Our completed wells rely on very basic industry technology.
 
Our development activities in the Cherokee Basin encompass a program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. We believe we have approximately 200 additional wellbores that are candidates for recompletion to multi-seam producers. 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 $28,000 to $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. However, in the long term, we believe the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production, a higher return on capital, and an increase in the ultimate recoverable reserves available per well.
 
Appalachian Basin
 
The Appalachian Basin is one of the largest and oldest producing basins within the United States. It is a northeast to southwest trending, elongated basin that deepens with thicker sections to the east. This basin takes in southern New York, Pennsylvania, eastern Ohio, extreme western Maryland, West Virginia, Kentucky,


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extreme western/northwestern Virginia, and portions of Tennessee. The basin is bounded on the east by a line of metamorphic rocks known as the Blue Ridge province which is thrusted to the west over the basin margin. Most prospective sedimentary rocks containing hydrocarbons are found at depths of approximately 1,000-9,000 feet with shallowest production in areas where oil and gas are seeping from the outcrop. Most productive horizons are found in sedimentary strata of Pennsylvanian, Mississippian, Devonian, Silurian, and Ordovician age. The Appalachian Basin has been an active area for oil and gas exploration, production and marketing since the mid-1800s. Although deeper zones are of interest, the main exploration and development targets are the Mississippian and Devonian sections.
 
Our main area of interest in the Appalachian Basin is within West Virginia, where there are producing formations at depths of 1,500 feet to approximately 8,000 feet. Specifically, our main production targets 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 members, Rhinestreet Shales). Although deeper targets are of interest (Onondaga and Oriskany), they are of lesser importance. The Mississippian formations are a conventional petroleum reservoir with the Devonian sections being a non-conventional energy resource.
 
The method for exploring and drilling these targets is different in several aspects. The Mississippian and Upper Devonian sections are explored through vertical drilling. The lower Marcellus section is explored by both vertical and horizontal drilling. The Mississippian section is identified by distinct sand and limestone zones with conventional porosity and permeability. Depths range from 1,000-2,500 feet deep. The Upper Devonian sands, siltstones, and shales are identified as multiple stacked pay lenses with depths ranging from 2,500-7,000 feet deep. The Marcellus Shale ranges in depth from 5,900 feet in portions of West Virginia to 7,100 feet in other portions of West Virginia. In certain areas of our development rights, vertical wells are drilled with combination completions in the Mississippian, Upper Devonian, and the Marcellus. Occasionally, vertical wells might only complete a single section of the three prospective pay intervals.
 
Our technical team has extensive experience in vertical and horizontal exploration, development and production. We have identified areas within the Appalachian Basin that we believe are prospective for both vertical and horizontal targets. As of December 31, 2009, we had development rights to acreage in approximately 18 counties within the Appalachian Basin. We have identified, based on reserves as of December 31, 2009, approximately 25 gross proved undeveloped drilling locations. Certain counties are vertical drilling targets for development and other counties are horizontal development targets. We believe there are over 331 gross vertical locations that would include potential production from one or all three of the Mississippian, Upper Devonian Sands, and Siltstones. We believe there are approximately 84 gross horizontal locations that would include the primary target for the Marcellus formation. In 2009, we completed two horizontal wells located in Wetzel County, West Virginia. This county in particular, along with Lewis County, West Virginia, is prospective for horizontal drilling in the Marcellus. Depths to the Marcellus in Lewis County and Wetzel County range from 6,300 feet to 7,200 feet. The thickness of the Marcellus in these counties ranges from just over 50 feet thick to over 90 feet thick.
 
Appalachian Basin Projects
 
As of December 31, 2009, our Appalachian Basin estimated net proved reserves totaled 18.9 Bcfe and were producing approximately 2.9 Mmcfe/d. During 2009, we drilled and completed one gross vertical well and completed two gross horizontal wells in Wetzel County, West Virginia, all of which are currently producing. The two horizontal wells were drilled and completed at a gross cost of $6.4 million and $5.3 million, respectively, while the vertical well was drilled and completed at a cost of $1.1 million. The two horizontal wells and one vertical well had initial production rates of 2.7 Mmcf/d, 1.3 Mmcf/d and 1.8 Mmcf/d, which have since declined to average production rates of 1.3 Mmcf/d, 0.2 Mmcf/d and 0.5 Mmcf/d, respectively. We have a net working interest of 50% in these three wells.
 
For 2010, we have budgeted net capital expenditures of approximately $20 million to drill and complete three vertical wells and six horizontal wells and approximately $2.5 million for land, equipment and connections in the Appalachian Basin. Each well will be drilled on a location that is classified as containing


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proved reserves in our December 31, 2009 reserve report. The expenditure of these funds is subject to capital being available.
 
Central Oklahoma Oil Properties
 
Our primary Oklahoma oil producing properties are located in Seminole and Pottawatomie counties located in south central Oklahoma. Oil was discovered in this area in 1926. Primary oil productive formations have included Hunton, Misener, Sylvan, Viola, Wilcox, Simpson and Oil Creek. Since discovery, these properties have undergone several phases of development. The Hunton Limestone is the main producing formation in the area. The Hunton formation is approximately 4100 feet in depth and ranges from 25 to 120 feet in thickness across the properties. Oil is produced from zones of lenticular porosity development. Primary oil recovery is limited by the discontinuous nature of the porosity development and early attempts to waterflood the Hunton had generally poor results. Today, high water cut Hunton oil is produced via numerous vertical production wells. Oil and produced formation water are separated at the surface and the produced water disposed, on-site, primarily into the underlying Wilcox sands. We believe that significant Hunton oil reserves remain trapped in the discontinuous porosity zones and plan to further develop this reservoir using horizontal drilling and production technologies when capital is available.
 
Oil and Gas Data
 
Reserves categories
 
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience 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 — 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. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although probable and possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by us.
 
Estimated Reserves
 
The following table presents our estimated net proved, probable and possible oil and gas reserves relating to our oil and natural gas properties as of December 31, 2009 based on our reserve reports as of such date. The data was prepared by the independent petroleum engineering firm Cawley, Gillespie & Associates, Inc. Reserves at December 31, 2009 were determined using the unweighted arithmetic average of the first day of the month price for each month from January through December 2009, which we refer to as the 12-month average price as of December 31, 2009, of $61.18 per barrel of oil and $3.87 per Mmbtu of gas.
 
                         
    Natural Gas (Bcf)   Oil (MMbbl)   Total (Bcfe)(1)
 
Proved reserves
                       
Developed
    62.1       0.78       66.8  
Undeveloped
    7.7       0.05       8.0  
                         
Total proved reserves
    69.8       0.83       74.8  
                         
Total probable reserves
    4.5             4.5  
                         
Total possible reserves
    9.1             9.1  
                         
 
 
(1) Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.


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Proved Undeveloped Reserves
 
At December 31, 2009, we had 7,971 Mmcfe of proved undeveloped reserves. During 2009, due to liquidity constraints, we did not convert any reserves from proved undeveloped to proved developed. Proved undeveloped reserves decreased from 2008 due to the significant decrease in prices used to determine our reserves. We do not have proved undeveloped reserves that will require more than five years to develop.
 
Sensitivity of Reserves to Prices and Costs
 
Fluctuations in the prices and costs used in the estimation of reserves can cause significant variations in the resulting reserve calculation. We believe it would be meaningful to consider different price and cost sensitivities to the reserve calculation presented above, particularly with respect to transportation costs following consummation of the recombination. The following table represents reserve amounts as of December 31, 2009 under three different pricing and cost scenarios explained below. The reserves presented under the alternative price and cost assumptions have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.
 
                                                                         
    Sensitivity of Reserves to Prices and Costs
 
    As of December 31, 2009  
    SEC
          Recombined
 
    Modernization
    Recombined
    NYMEX
 
    Methodology(1)     Methodology(2)     Methodology(3)  
    Gas
    Oil
    Total
    Gas
    Oil
    Total
    Gas
    Oil
    Total
 
    (Bcf)     (MMbbl)     (Bcfe)     (Bcf)     (MMbbl)     (Bcfe)     (Bcf)     (MMbbl)     (Bcfe)  
 
Proved reserves
                                                                       
Developed
    62.1       0.78       66.8       96.5       0.78       101.2       158.9       0.87       164.1  
Undeveloped
    7.7       0.05       8.0       8.8       0.05       9.1       58.4       0.05       58.7  
                                                                         
Total proved reserves
    69.8       0.83       74.8       105.3       0.83       110.3       217.3       0.92       222.8  
                                                                         
Total probable reserves
    4.5             4.5       31.7       0.33       33.7       57.4       0.33       59.4  
Total possible reserves
    9.1             9.1       9.1             9.1       94.8       0.06       95.2  
                                                                         
                                                                         
    SEC
          Recombined
 
    Modernization
    Recombined
    NYMEX
 
    Methodology(1)     Methodology(2)     Methodology(3)  
    (in thousands)  
                                                                         
PV-10 value(4):
                                                                       
Proved reserves
          $ 50,559                     $ 99,901                     $ 431,901          
Probable reserves
            435                       2,120                       63,437          
Possible reserves
            139                       139                       75,996          
 
 
(1) Amounts determined based on the recently adopted SEC final rule “Modernization of Gas and Oil Accounting”. The prices used in this calculation equal the 12-month average price as of December 31, 2009 used in the table above under “— Estimated Reserves.” The transportation cost on our Cherokee Basin production was $1.70 per Mcf, which is based on the gathering rate charged under the midstream services and gas dedication agreement between Bluestem Pipeline, LLC and QELP in effect during 2009.
 
(2) The prices used in this calculation are the same as those described in footnote 1. This scenario assumes that the midstream services and gas dedication agreement, which after the recombination is an intercompany agreement, is no longer in effect and therefore utilizes our current estimate of direct pipeline operating expense for our natural gas gathering pipeline system of $0.80 per Mcf.
 
(3) Amounts determined based on the publicly traded NYMEX 2010 to 2015 natural gas and oil forward curve as of February 1, 2010. The average 5 year forward price for natural gas was $6.38 per Mmbtu and the average 5 year forward price for crude oil was $82.75 per barrel. This scenario assumes that the midstream services and gas dedication agreement is no longer in effect and therefore utilizes our current estimate of direct pipeline operating expense for our natural gas gathering pipeline system of $0.80 per Mcf.


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(4) The PV-10 value of our reserves is a non-GAAP financial measure. PV-10 value is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure under generally accepted accounting principles. PV-10 value is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 value is equal to the standardized measure of discounted future net cash flows at a specified date before deducting future income taxes, discounted at 10%. Discounted future net cash flows are based on assumptions of future prices, future production costs and future development costs. However, as a result of our significant net operating loss carryfowards, we do not expect to incur future income tax liabilities for the foreseeable future and therefore have an effective future income tax rate of zero. As such, there is no difference between the standardized measure and the PV-10 value of our reserves under the different methodologies. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our reserves, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves as of the specified dates.
 
The reserve data above represents estimates only. Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on geoscience and engineering data. There are uncertainties inherent in the interpretation of these 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 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.
 
In addition to proved reserves, which are those quantities of natural gas and oil that can be estimated with reasonable certainty to be economically producible within the time period provided by applicable SEC rules, we disclose in this annual report our “probable” and “possible” reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves include additional reserves that are less certain to be recovered than probable reserves. These estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by us.
 
Internal Controls
 
A significant component of our internal controls in our reserve estimation effort is our practice of using an independent third-party reserve engineering firm to prepare 100% of our year-end proved reserves and, for 2009, our probable and possible reserves. The qualifications of this firm are discussed below under “Independence and Qualifications of Reserve Preparer.” While we do not have a formal review process, reserves are presented to management and the board of directors for review and approval.
 
Our internal reserve engineers report to our Director of Reservoir Engineering and Geology, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to our independent third party reserve engineers to estimate our year-end reserves. Our internal reserve engineer staff consists of four degreed petroleum/mechanical/chemical engineers, with between four and 28 years reservoir engineering experiences, and between three months and three years of experience managing our reserves. All of our internal reserve engineers are members of the Society of Petroleum Engineers.


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Production Volumes, Sales Prices and Production Costs
 
The following table sets forth information regarding our oil and natural gas properties. The oil and gas 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.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
 
Net Production:
                       
Gas (Bcf)
    21.24       21.33       16.98  
Oil (Bbls)
    83,015       69,812       7,070  
Gas equivalent (Bcfe)
    21.73       21.75       17.02  
Oil and Gas Sales ($ in thousands):
                       
Gas sales
  $ 75,106     $ 156,051     $ 104,853  
Oil sales
    4,787       6,448       432  
                         
Total oil and gas sales
  $ 79,893     $ 162,499     $ 105,285  
Avg Sales Price (unhedged):
                       
Gas ($ per Mcf)
  $ 3.54     $ 7.32     $ 6.18  
Oil ($ per Bbl)
  $ 57.66     $ 92.36     $ 61.10  
Gas equivalent ($ per Mcfe)
  $ 3.68     $ 7.47     $ 6.19  
Avg Sales Price (hedged)(1):
                       
Gas ($ per Mcf)
  $ 8.11     $ 7.02     $ 6.60  
Oil ($ per Bbl)
  $ 69.93     $ 90.44     $ 61.10  
Gas equivalent ($ per Mcfe)
  $ 8.19     $ 7.18     $ 6.61  
Oil and gas operating expenses ($ per Mcfe):
                       
Production costs, excluding production and property taxes
  $ 1.19     $ 1.58     $ 1.71  
Production and property taxes
  $ 0.35     $ 0.45     $ 0.42  
Net Revenue ($ per Mcfe)
  $ 2.14     $ 5.44     $ 4.06  
 
 
(1) Data includes the effects of our commodity derivative contracts that do not qualify for hedge accounting. The following table summarizes the realized gains (losses) by commodity type by period:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
 
Realized gain (loss) on hedges
                       
Gas Hedges
  $ 97,130     $ (6,254 )   $ 7,279  
Oil Hedges
  $ 1,018     $ (134 )      
                         
Total
  $ 98,148     $ (6,388 )   $ 7,279  
                         
 
The following tables present our production, average sales prices and production costs, excluding production and property taxes, by area for the year ended December 31, 2009.
 
                         
    Year Ended December 31, 2009
    Natural Gas (Bcfe)   Oil (Bbls)   Total (Bcfe)
 
Production:
                       
Cherokee Basin
    20.2       9,474       20.26  
Appalachia
    0.96       18,432       1.06  
Central Oklahoma and other
    0.08       55,109       0.41  
 


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    Natural Gas (per Mcfe)   Oil (per Bbl)   Total (per Mcfe)
 
Average Sales Prices
                       
Cherokee Basin
  $ 3.31     $ 54.66     $ 3.32  
Appalachia
    8.30       51.90       8.34  
Central Oklahoma and other
    4.30       60.10       8.91  
 
         
    Year Ended
    December 31, 2009
 
Production Costs (per Mcfe):
       
Cherokee Basin
  $ 1.04  
Appalachia
    3.11  
Central Oklahoma and other
    3.67  
 
Producing Wells and Acreage
 
The following tables set forth information regarding our ownership of producing wells and total acres as of December 31, 2009, 2008 and 2007. Of our nonproducing wells, we cannot determine, without unreasonable effort or expense, the number of wells mechanically capable of producing as of such dates.
 
                                                 
    Producing Wells        
    Gas   Oil   Total
    Gross   Net   Gross   Net   Gross   Net
 
December 31, 2007
    2,225       2,218.2       29       28.1       2,254       2,246.3  
December 31, 2008(1)
    2,873       2,825.0       82       80.2       2,955       2,905.2  
December 31, 2009(2)
    2,442       2,397.8       48       43.7       2,490       2,441.6  
 
 
(1) Increase includes approximately 500 gross Appalachian Basin wells acquired in the acquisition of PetroEdge Resources (WV) LLC in July 2008, or the PetroEdge acquisition, and 55 gross wells acquired in Seminole County, Oklahoma.
 
(2) Decrease from 2008 is due primarily to shutting in wells as a result of low natural gas prices.
 
                                                 
    Acreage  
    Producing(1)     Nonproducing     Total  
    Gross     Net     Gross     Net     Gross     Net  
 
December 31, 2007(2)
    403,048       393,480       204,104       187,524       607,152       581,004  
December 31, 2008(3)(4)
    464,702       446,537       208,224       180,707       672,926       627,244  
December 31, 2009(5)(6)
    446,129       432,008       139,018       130,161       585,147       562,169  
 
 
(1) Includes acreage held by production or the payment of shut in royalties under the terms of the lease.
 
(2) Includes acreage in the states of Kansas, Oklahoma, New Mexico, Texas and Pennsylvania.
 
(3) Includes acreage in the states of Kansas, Oklahoma, New York, Pennsylvania, and West Virginia.
 
(4) Includes approximately 37,723 gross and 31,565 net acres attributable to various farm-out agreements or other mechanisms in the Appalachian Basin. Approximately 6,912 net acres were earned and approximately 24,653 net acres were unearned under these agreements as of December 31, 2008. There are certain drilling or payment obligations that must be met before this unearned acreage is earned.
 
(5) Includes approximately 37,805 gross and 31,883 net acres attributable to various farm-out agreements or other mechanisms in the Appalachian Basin. Approximately 10,058 net acres are earned and approximately 21,825 net acres are unearned under these agreements as of December 31, 2009. There are certain drilling or payment obligations that must be met before this unearned acreage is earned.
 
(6) Includes acreage in the states of Kansas, Oklahoma, West Virginia, Pennsylvania and New York.

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As of December 31, 2009, in the Cherokee Basin, we had 338,235 net developed acres and 177,946 net undeveloped acres. As of December 31, 2009, in the Appalachian Basin, we had 9,771 net developed acres and 34,736 net undeveloped acres. 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
 
The table below sets forth the number of wells completed at any time during the period, regardless of when drilling was initiated. Our drilling, recompletion, abandonment, and acquisition activities for the periods indicated are shown below (this information is inclusive of all basins and areas):
 
                                                 
    Year Ended
    Year Ended
    Year Ended
 
    December 31,
    December 31,
    December 31,
 
    2009     2008     2007  
    Gross     Net     Gross     Net     Gross     Net  
 
Exploratory wells drilled:
                                               
Productive
                1       1              
Dry
    1       1       1       1              
Development wells drilled:
                                               
Productive
    4       2.5       339       338       572       572  
Dry
                                   
Wells plugged and abandoned
    11       11       17       17              
Wells acquired capable of production(1)
    9       1.6       551       514.5              
                                                 
Net increase in capable wells
    3       (5.9 )     875       837.5       572       572  
                                                 
Recompletion of old wells:
                                               
Capable of production
                14       14       50       49  
 
 
(1) Includes 53.5 net and 55 gross oil wells capable of production acquired in Seminole County, Oklahoma in February 2008. The remainder of the 2008 acquired wells were acquired as part of the PetroEdge acquisition.
 
Independence and Qualifications of Reserve Preparer
 
We engaged Cawley, Gillespie & Associates, Inc., third-party reserve engineers, to prepare our reserves as of December 31, 2009, 2008 and 2007. The technical person responsible for our reserve estimates at Cawley, Gillespie & Associates, Inc. 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. Cawley, Gillespie & Associates, Inc. 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.
 
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


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infrastructure for new wells (such as electric service, salt water disposal facilities, and gas feeder lines). The primary equipment categories owned by us are trucks, well service rigs, stimulation assets and construction equipment. We utilize third-party contractors on an “as needed” basis 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 are also able to realize significant cost savings because we can reduce delays in executing our plan of development, avoid paying price markups and are able to purchase our own supplies at bulk discounts. 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 well site construction. We have our own fleet of 24 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.
 
Oil and Gas Leases and Development Rights
 
As of December 31, 2009, we had approximately 4,200 leases covering approximately 562,169 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 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 oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 3.125% to 16.5% which further reduces the net revenue interest available to us to between 64.75% and 84.375%.
 
As of December 31, 2009, approximately 77% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.
 
In the Cherokee Basin, as of December 31, 2009, we held oil and gas leases on approximately 516,184 net acres, of which 124,180 net acres (24%) 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 75,621 net acres are scheduled to expire before December 31, 2010. If these leases expire and are not renewed, we will lose the right to develop the related properties.
 
We hold oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on 29,877 net acres in the Appalachian Basin 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. We are required to drill three gross gas wells by April 30, 2010 in order to maintain approximately 2,000 net acres. We must also drill an additional three gross gas wells by December 31, 2010 to maintain approximately an additional 6,000 net acres. Furthermore, we are currently required to drill an additional four gross wells in order to maintain 1,605 net acres in New York. The exact deadline for the drilling of these four wells is currently unclear, due to permitting delays caused by an environmental impact review being conducted by the state of New York. We may not be able to meet the drilling and payment obligations to earn or maintain all of this leasehold acreage.
 
Gas Gathering Systems
 
Our Cherokee Basin gas gathering system includes approximately 2,173 miles of low pressure gas gathering pipeline network. The system provides a market outlet for natural gas in a region of approximately 1,000 square miles in size and has connections to both intrastate and interstate delivery pipelines. We believe


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it is the largest gathering system in the Cherokee Basin with a current throughput capacity of approximately 85 Mmcf/d and delivers virtually all its gathered gas into Southern Star Central Gas Pipeline at multiple interconnects. This gathering system includes 77 field compression units comprising approximately 48,000 horsepower of compression in the field (most of which are currently rented) as well as five CO2 amine treating facilities.
 
We gather on our gas gathering system substantially all of the natural gas we produce in the Cherokee Basin in addition to some natural gas produced by other companies. The pipeline network is a critical asset for our future growth in the Cherokee Basin because natural gas gathering pipelines are a costly component of the infrastructure required for natural gas production and such pipelines are not easily constructed.
 
During 2009, we connected two wells. We estimate that our cost for pipeline infrastructure in 2010 will be approximately $5.5 million to connect 108 gross wells in the Cherokee Basin that were previously drilled but not completed, if the outlook for commodity prices remains at the level where we believe the connection of these wells is justified and if we have available capital.
 
We also own and operate a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. As of December 31, 2009, this system has a maximum daily throughput of approximately 18 Mmcf/d. All of our Appalachian gas production is transported by this gas gathering pipeline network.
 
The table below sets forth the natural gas volumes gathered on our gas gathering pipeline networks during the years ended December 31, 2009 and 2008.
 
                 
    Year Ended December 31,
    2009   2008
 
Pipeline Natural Gas Vols (Mmcf):
               
Cherokee Basin
    26,083       27,093  
Appalachian Basin
    956       476  
 
Third-Party Gas Gathering
 
For services rendered to third parties, we retain a portion of the gas volumes sold. For 2009, approximately 6% of the gas transported on our natural gas gathering pipeline systems was for third parties.
 
Interstate Natural Gas Pipeline
 
The KPC Pipeline is an interstate natural gas transportation pipeline located in Kansas, Oklahoma and Missouri that we acquired in November 2007. The pipeline was assembled in the mid-1980’s from various crude oil transportation pipelines. Over the years, the KPC Pipeline has been reliant on Kansas Gas Services (“KGS”) and Missouri Gas Energy (“MGE”) for the majority of its revenue from firm capacity transportation contracts. The firm capacity transportation contract with MGE for approximately 46,000 Dth/d expired on October 31, 2009 and was not renegotiated or renewed. The pipeline has an approximate capacity of up to 160 MMcf/d. The KPC Pipeline is underutilized in terms of throughput and its prior owners did little to diversify markets. We are seeking to significantly increase opportunities to grow throughput to maximize the value of the KPC Pipeline, such as creating additional service options for both gas suppliers and consumers and developing additional pipeline interconnects to provide customers greater optionality for gas supply and market. During the fourth quarter of 2009, the KPC Pipeline added five new customers with various business services. In early October 2009, the FERC approved KPC’s request to provide Park and Loan services on the KPC Pipeline. This creates a new income opportunity for the KPC Pipeline as well as provides a value-adding service for customers as they balance gas supply and demand. We will continue to evaluate other opportunities and additional services, each intended to create value for the customer while providing incremental revenue for the KPC Pipeline.


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The management team responsible for the KPC Pipeline has short, intermediate and long-term strategies in place to stabilize and grow the KPC Pipeline asset base and cash flows. Many of these strategies are being pursued with a limited number already in implementation. It may take several years to reach its ultimate potential, which may never be achieved. Management believes that the KPC Pipeline is a valuable asset with significant potential.
 
Impairment of Gas Gathering and Interstate Pipelines
 
Certain events during the fourth quarter of 2009 indicated our pipeline assets and intangibles could be impaired. We were unable to negotiate a new contract with one of our major customers for the KPC Pipeline, MGE. Our existing contract with MGE expired in October 2009, although prior to the expiration we believed that the contract could be extended or renegotiated with MGE or replaced by another customer. In addition, while we were successful in negotiating amendments to our credit facilities in December 2009, the amended credit facilities imposed limits 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.
 
Based on our analysis, we determined that the carrying value of our pipeline assets exceeded their fair values by approximately $164.7 million and recorded an impairment for such amount in the fourth quarter of 2009. In addition, we determined that our customer-related contracts, held by KPC and presented as intangible assets on the balance sheet, were also impaired. We recognized an impairment of $1.0 million on our intangible assets. No such impairment was required at December 31, 2008.
 
Marketing and Major Customers
 
Exploration and Production
 
In the Cherokee Basin for 2009, substantially all of our gas production was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”). The ONEOK sales agreement is a monthly evergreen agreement, cancellable by either party. In the fourth quarter of 2009, we diversified our gas sales in the Cherokee Basin between six markets, including sales directly to end use customers. We will seek to continue to diversify our sales portfolio balancing price, credit risk and volume risk. These efforts also are expected to reduce marketing risk and provide competition to optimize the price we receive for our production.
 
During 2009, we sold 100% of our oil production in the Cherokee Basin to Coffeyville Refining, 100% of our oil production in Central Oklahoma to Sunoco Partners Marketing & Terminals L.P. and 100% of our oil production in the Appalachian Basin to Appalachian Oil Purchasers, a division of Clearfield Energy.
 
Approximately 86% of our 2009 Appalachian Basin natural gas production was sold to Dominion Field Services under a mix of fixed price and index based sales contracts and a market sensitive contract. Another 7% was sold to Hess Corporation under a mix of fixed price and index based sales contracts. The remainder of the Appalachian natural gas production was sold to various purchasers under market sensitive pricing arrangements. None of these remaining sales exceeded 3% of total Appalachian Basin natural gas production. Due to the history of problematic Northeastern pipeline constraints, we have secured a firm transportation agreement for a portion of our gas to ensure uninterrupted deliveries of our natural gas production.
 
If we were to lose any of these oil or natural gas purchasers, we believe that we would be able to promptly replace them. If we were to terminate agreements with any of our current oil or natural gas purchasers, there are multiple options for marketing our commodities. We have discussed direct sales with both refineries and natural gas consuming industrials as well as establishing agreements with various marketing companies. The physical location of both our oil and natural gas provides ample options for marketing the commodities to creditworthy parties.
 
Interstate Pipeline
 
Historically, the two primary shippers on the KPC Pipeline were Kansas Gas Service and Missouri Gas Energy. For 2009, approximately 59% and 32% of the revenue from the KPC Pipeline were from firm capacity


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transportation contracts with KGS and MGE, respectively. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities. MGE, a division of Southern Union Company, is a natural gas distribution company that serves over one-half million customers in 155 western Missouri communities. The firm capacity transportation contract with MGE for approximately 46,000 Dth/d expired on October 31, 2009 and was not renegotiated or renewed. KGS’s contracts for firm capacity on the KPC Pipeline include contracts for the following capacities and expiration dates:
 
     
Capacity
 
Time Period
 
57,568 Dth/d
  November 1, 2009 through October 31, 2012
44,636 Dth/d(*)
  November 1, 2009 through October 31, 2015
43,171 Dth/day(*)
  November 1, 2015 through October 31, 2017
12,000 Dth/d
  November 1, 2009 through October 31, 2013
6,900 Dth/d
  November 1, 2002 through September 30, 2017
6,857 Dth/d
  November 1, 2002 through March 31, 2017
 
 
(*) yearly average, some volumes adjusted for seasonal needs.
 
Commodity Derivative Activities
 
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 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 contracts priced at a fixed discount to NYMEX oil prices. Due to the historical volatility of oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for the sale of our future production. While we believe that the stabilization of prices and production afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising oil or natural gas prices. As a result of rising commodity prices, we may recognize additional charges to future periods. We hold derivative contracts based on Southern Star and NYMEX oil and natural gas prices, and we have fixed price sales contracts with certain customers in the Appalachian Basin. These derivative contracts and fixed price contracts mitigate our risk of fluctuating commodity prices but do not eliminate the potential effects of changing commodity prices. We limit our exposure to basis differential risk by generally entering into derivative contracts that are based on the same indices on which the underlying sales contracts are based or by entering into basis swaps for the same volume of hedges that settle based on NYMEX prices.
 
As of December 31, 2009, we held derivative contracts covering approximately 49.7 Bcf of natural gas through 2013 and 30,000 Bbls of oil through 2010. Approximately 12.5 Bcf of our Cherokee Basin natural gas production is hedged utilizing contracts that settle on Southern Star prices at a weighted average price of $6.24/Mmbtu for 2010, and approximately 7.0 Bcf of our Cherokee Basin natural gas production is hedged utilizing contracts that settle on Southern Star prices at a weighted average price of $6.51/Mmbtu for 2011 through 2012. Approximately 3.6 Bcf of our Cherokee Basin natural gas production is hedged utilizing contracts that settle on NYMEX prices at a weighted average price of $6.31/Mmbtu for 2010, and approximately 26.6 Bcf of our Cherokee Basin natural gas production is hedged utilizing contracts that settle on NYMEX prices at a weighted average price of $7.18/Mmbtu for 2011 through 2013. Our fixed price contracts hedge approximately 0.12 Bcf of our Appalachian Basin natural gas production at a weighted average price of $8.76/Mmbtu for the first quarter of 2010. We also held basis swaps covering approximately 3.6 Bcf of our Cherokee Basin natural gas production that settle on the difference between NYMEX and Southern Star prices at a weighted average difference of $0.63/Mmbtu for 2010 and approximately 26.6 Bcf of our Cherokee Basin natural gas production at a weighted average difference of $0.69 for 2011 through 2013.
 
As of December 31, 2009, approximately 30,000 Bbls of our Central Oklahoma crude oil production is hedged utilizing NYMEX contracts at a weighted average price of $87.50/Bbl for 2010. For more information


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on our derivative contracts, see Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report on Form 10-K.
 
Competition
 
Exploration and Production
 
We operate in a highly competitive environment for acquiring properties, marketing oil and gas and employing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.
 
Gas Gathering
 
Our gas gathering systems experience minimal competition because approximately 94% of these systems’ throughput is attributable to our production.
 
Interstate Pipelines
 
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. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company in the Kansas City market, and Southern Star Central Gas Pipeline, Atmos Energy Corporation and Mid-Continent Market Center in the Wichita market.
 
Operating Hazards and Insurance
 
The oil and natural gas business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations.
 
In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.
 
In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We do not carry business interruption insurance or protect against loss of revenues. Any insurance we obtain may not be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.
 
We participate in a small number of our wells on a non-operated basis, and accordingly are limited in our ability to control the risks associated with oil and natural gas operations with respect to those wells.


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Title to Properties
 
Oil and Natural Gas 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 thorough title examination and perform curative work with respect to significant defects. 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 on such property. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas 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 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 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.
 
Seasonal Nature of Business
 
Exploration and Production
 
Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the spring and summer months. These seasonal anomalies can pose challenges for meeting our well development


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objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
 
In addition, freezing weather, winter storms 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, which 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.
 
Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for natural gas. Seasonal anomalies such as mild winters and hot summers sometimes lessen this fluctuation.
 
Interstate Pipelines
 
Due to the nature of the markets served by the KPC Pipeline, primarily the metropolitan 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. This provides for higher operating costs in the winter months. On a revenue basis, KPC’s firm capacity transportation agreements provide for greater use in the winter months. KPC currently generates a disproportionate share of its revenue in the winter months.
 
Environmental, Health and Safety Matters and Regulation
 
General
 
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment, the generation, storage, transportation, handling and disposal of wastes, the safety of employees and governing the protection of human health and safety. These laws and regulations may, among other things:
 
  •  require the acquisition of various permits before drilling commences;
 
  •  limit or curtail some or all of the operations of facilities deemed in non-compliance with permits or other legal requirements;
 
  •  restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, gathering, treating and transportation activities;
 
  •  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas; and
 
  •  require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore, remediate or mitigate impacted environmental media.
 
These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The oil and gas industry, in particular, recently has come under greater scrutiny by environmental regulators and non-governmental organizations. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for or restrictions or other regulatory burdens on operations of the oil and gas industry could have a significant impact on our operating costs.
 
The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.


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Waste Management
 
The Resource Conservation and Recovery Act, or 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 federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. However, 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. Also, 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.
 
Comprehensive Environmental Response, Compensation, and Liability Act
 
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as the Superfund law, imposes strict, and under certain circumstances joint and several, liability for investigation and remediation costs on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may also be subject to liability for damages to natural resources, and for the costs of certain environmental studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
 
We currently own, lease or operate numerous properties that have been used for oil and gas exploration, production, and transportation for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, including wastes disposed of or released by us or prior owners or operators in accordance with then current laws or otherwise, remediate contaminated property, perform plugging or pit closure operations to prevent future contamination, or take other environmental response actions.
 
Water Discharges and Water Quality
 
The Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas production operations and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA may require appropriate containment berms and similar structures to help prevent the contamination of navigable


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waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
 
Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes controls relating to the drilling and operation of the wells as well as the quality of the injected wastewaters. This program is designed to protect drinking water sources and requires a permit from the EPA or the designated state agency. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.
 
Vast quantities of natural gas deposits exist in deep shale formations. It is customary in our industry to recover natural gas from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating artificial cracks, or fractures, in shale formations deep underground by pumping water, sand and other additives under high pressure into a shale gas formation. These deep shale gas formations are often geologically separated and isolated from any fresh ground water supplies by thousands of feet of protective rock layers. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into overlying aquifers. Legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing. Current proposals include the elimination of the exclusion of hydraulic fracturing from the definition of “underground injection” under the SDWA, which would subject hydraulic fracturing to SDWA permitting requirements. Such efforts could have an adverse effect on our operations.
 
The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution: prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
 
Air Emissions
 
The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Moreover, depending on the state-specific statutory authority, states may be able to impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.
 
Permits and related compliance obligations under the CAA or state counterpart laws, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and gas exploration, production and transportation operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a


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regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
 
Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or use specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Historically, air pollution control has become more stringent over time. This trend is expected to continue. The cost of technology and systems to control air pollution to meet regulatory requirements is significant today. These costs are expected to increase as air pollution control requirements increase. However, any new requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
 
Climate Change
 
Legislative and regulatory measures to address concerns that emissions of certain gases, commonly referred to as “greenhouse gases” (including carbon dioxide and methane) (“GHGs”), may be contributing to warming of the Earth’s atmosphere are in various phases of discussions or implementation at the international, national, regional, and state levels. The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. In the United States, federal legislation requiring GHG controls is under consideration. In addition, EPA is taking steps that would result in the regulation of GHGs as pollutants under the Clean Air Act (CAA).
 
In September 2009, EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule, which took effect on December 29, 2009. This rule establishes a comprehensive scheme of regulations that require monitoring and reporting of GHG emissions on an annual basis by operators of stationary sources in the U.S. emitting more than established annual thresholds of carbon dioxide-equivalent GHG emissions. Monitoring and recordkeeping of GHG emissions requirements began January 1, 2010 and reporting requirements obligations begin March 31, 2011 for emissions occurring in 2010. Although the GHG reporting rule does not control GHG emission levels from any facilities, it will still cause us to incur monitoring and reporting costs for GHG emissions that are subject to the rule. Some of our facilities include source categories that are subject to the GHG reporting requirements included in the final rule. Furthermore, in December 2009, EPA indicated that it had drafted and plans to propose additional GHG reporting rules specifically for the oil and gas industry. The proposal is currently undergoing interagency review. The proposed rules will likely apply to natural gas transmission, compression and distribution, i.e., fugitive and vented methane emissions, and potentially to emissions from other activities we conduct. If EPA adopts regulations that require reporting of fugitive and vented methane emissions from the oil and gas industry, this will increase our monitoring and reporting costs.
 
In December 2009, EPA published a final rule, the “Endangerment Finding”, finding that GHGs in the atmosphere endanger public health and welfare, and that emissions of GHGs from mobile sources cause or contribute to GHG pollution. The Endangerment Finding took effect on January 14, 2010. While the Endangerment Finding does not impose any direct requirements on industry or other entities, the rule allows EPA to promulgate motor vehicle GHG emission standards. EPA is expected to promulgate such standards in March 2010 and they would take effect sometime thereafter. Motor vehicle emission standards could impact our operations by effectively reducing demand for motor fuels from crude oil. Furthermore, EPA has asserted that final motor vehicle GHG emission standards will trigger construction and operating permit requirements for stationary sources. In September 2009, EPA proposed a rule that would tailor permit applicability thresholds for GHG emissions such that only large stationary sources will be required to obtain air permits for new or modified facilities. Promulgation of the motor vehicle standards and resulting triggering of permitting requirements for GHG emissions from stationary sources could potentially affect our operations and ability to obtain


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air permits for new or modified facilities. EPA’s Endangerment Finding has however been challenged and will likely be subject to litigation, and legislation has been proposed to overturn or delay its implementation.
 
Legislation and regulations related to control or reporting of GHG emissions are also in various stages of discussions or implementation in many of the states in which we operate. Lawsuits have been filed seeking to force the federal government to regulate GHG emissions under the CAA and to require individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects.
 
Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business could adversely affect the demand for oil and gas, and depending on the particular program adopted 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 GHG emissions, pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program. It could also affect entities that provide goods and services to us and indirectly have an adverse affect on our business as a result of increases in costs or availability of goods and services.
 
In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business also could be negatively affected by climate change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our physical assets, impact our ability to conduct operations and/or result in a disruption of our customer’s operations. These and other climate change related physical changes could also affect entities that provide goods and services to us and indirectly have an adverse affect on our business as a result of increases in costs or availability of goods and services. Although we do not believe that we would be impacted to a greater degree than other similarly situated producers of oil and natural gas, a stringent GHG control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and natural gas we produce. Please read Part I, Item 1A. “Risk Factors— Risks Related to Our Business— Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and transportation operations.”
 
Hydrogen Sulfide
 
Hydrogen sulfide gas is a byproduct of sour gas treatment. Exposure to unacceptable levels of hydrogen sulfide (known as sour gas) is harmful to humans, and prolonged exposure can result in death. We employ numerous safety precautions to ensure the safety of our employees. There are various federal and state environmental and safety requirements that apply to facilities using or producing hydrogen sulfide gas. Notwithstanding compliance with such requirements, common law causes of action are available to persons damaged by exposure to hydrogen sulfide gas.
 
National Environmental Policy Act
 
Oil and gas exploration and production activities on federal lands or that require certain federal permits are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future or initiate other projects subject to NEPA requirement, those activities would need to undergo the NEPA review process including potential evaluation of any GHG impacts from proposed activities. This process has the potential to delay and potentially prevent the development of an oil and gas project.


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Endangered Species Act
 
The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Although we believe that our current operations do not affect endangered or threatened species or their habitats, the existence of endangered or threatened species in areas of future operations and development could cause us to incur additional mitigation costs or become subject to construction or operating restrictions or bans in the affected areas.
 
OSHA and Other Laws and Regulation
 
We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other comparable laws.
 
We believe that we are in substantial compliance with all existing environmental and safety laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2009. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2010. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, or results of operations.
 
Other Regulation of the Oil and Gas Industry
 
The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
 
Exploration and Production
 
Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
 
  •  the location of wells;
 
  •  the method of drilling and casing wells;


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  •  the surface use and restoration of properties upon which wells are drilled;
 
  •  the plugging and abandoning of wells; and
 
  •  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 other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may 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 the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, some states impose a production or severance tax with respect to the production and sale of oil, gas and gas liquids within its jurisdiction.
 
The Cherokee Basin has been an active oil and natural gas 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 into with the landowner. 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. The Kansas Corporation Commission’s current interpretation of Kansas law is consistent with our position.
 
Interstate Pipelines
 
The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation of natural gas and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. 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 also 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 operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other interstate pipelines with which we compete.
 
The Energy Policy Act of 2005, or EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the Natural Gas Act of 1938, or NGA, to prohibit market manipulation and 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 to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes 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. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.
 
Although natural gas prices are currently unregulated, FERC promulgated regulations in December 2007 requiring natural gas sellers to submit an annual report, beginning in July 2009, reporting certain information regarding natural gas purchases and sales (e.g., total volumes bought and sold, volumes bought and sold and


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index prices). Additionally, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation or regulations to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress, the FERC, or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and gas liquids are not currently regulated and are made at market prices.
 
State Severance, Production and Other Taxes
 
Kansas currently imposes a severance tax on the gross value of oil and natural gas produced from wells having an average daily production during a calendar month with a gross value of more than $87 per day. Kansas also imposes oil and natural gas conservation assessments per barrel of oil and per 1,000 cubic feet of gas produced. In general, oil and natural gas leases and oil and natural gas wells (producing or capable of producing), including all equipment associated with such leases and wells, are subject to an ad valorem property tax.
 
Oklahoma imposes a monthly gross production tax and excise tax based on the gross value of the oil and natural gas produced. Oklahoma also imposes an excise tax based on the gross value of oil and natural gas produced. All property used in the production of oil and natural gas is exempt from ad valorem taxation if gross production taxes are paid. Lastly, the rate of taxation of locally assessed property varies from county to county and is based on the fair cash value of personal property and the fair cash value of real property.
 
West Virginia imposes a severance tax equal to five percent of the gross value of oil and natural gas produced and a similar severance tax on CBM produced. West Virginia also imposes an additional annual privilege tax equal to 4.7 cents per Mcf of natural gas produced.
 
New York imposes an annual oil and natural gas charge based on the amount of oil or natural gas produced each year.
 
States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may limit the amounts of oil and natural gas that may be produced from our wells and may limit the number of wells or locations drilled.
 
Federal Regulation of Transportation of Gas
 
FERC regulates interstate natural gas pipelines pursuant to the NGA, NGPA and EP Act 2005. Generally, FERC’s authority over interstate natural gas pipelines extends to:
 
  •  rates and charges for natural gas transportation services;
 
  •  certification and construction of new facilities;
 
  •  extension or abandonment of services and facilities;
 
  •  maintenance of accounts and records;
 
  •  relationships between pipelines and certain affiliates;
 
  •  terms and conditions of service;
 
  •  depreciation and amortization policies;
 
  •  acquisition and disposition of facilities; and
 
  •  initiation and discontinuation of services.
 
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


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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. 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.
 
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. We believe our natural gas gathering pipeline facilities meet the traditional tests used by FERC to distinguish gathering facilities from transmission facilities. 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. 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 would substantially increase our operating costs and would adversely affect our profitability.
 
Additionally, while gathering facilities and other non-interstate pipelines are generally exempt from FERC’s jurisdiction, FERC adopted internet posting requirements in November 2008 that are applicable to certain gathering facilities and other non-interstate pipelines meeting size and other thresholds. Various parties requested rehearing of the FERC rule adopting the new posting requirements and the FERC granted an extension of time to comply with the new requirements until 150 days following the issuance of an order addressing the requests for rehearing. On January 21, 2010, FERC issued a rehearing order that generally upheld the new reporting requirements while making certain revisions and clarifications. Importantly, FERC upheld provisions specifying, among other things, that the new reporting requirements are only applicable to 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 new posting requirements. Nevertheless, it is possible that we could become subject to the new 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 new posting requirements, we would likely incur additional compliance expenses.
 
State Regulation of Natural Gas Gathering Pipelines
 
Our natural gas 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 compliant-based rate regulation. We are licensed as an operator of a natural gas gathering system with the Kansas Corporation Commission, or 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, New York or West Virginia.
 
On those portions of our gas 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. 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


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our rates with respect to the wells that were the subject of 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 and, for the most part, is not subject to 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 federal and state 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 also 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, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.
 
Pipeline Safety
 
Our pipelines are subject to regulation by the U.S. Department of Transportation, or 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. The NGPSA covers the pipeline transportation of natural gas and other gases and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. 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.
 
Other
 
In addition to existing laws and regulations, the possibility exists that new legislation or regulations may be adopted which would 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, FERC, the Minerals Management Service, 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. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely.
 
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. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. 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.


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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 to ensure that our operations are conducted in substantial regulatory compliance.
 
Employees
 
As of December 31, 2009, we had a staff of 156 field employees in offices located in Kansas, Oklahoma, Pennsylvania, and West Virginia. We have 69 pipeline operations employees. We have 73 executive and administrative personnel located at our headquarters in Oklahoma City and our office in Houston, Texas. None of our employees are covered by a collective bargaining agreement. Management considers its relations with our 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:
 
  •  Audit Committee Charter;
 
  •  Compensation Committee Charter;
 
  •  Nominating Committee Charter; and
 
  •  Code of Business Conduct and Ethics.


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GLOSSARY OF SELECTED TERMS
 
The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. Some of the definitions below have been abbreviated from the applicable definition contained in Rule 4-10(a) of Regulation S-X.
 
Appalachian Basin.  One of the United States’ oldest oil and natural gas producing regions that extends from Alabama to Maine.
 
Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
Bbls/d.  Stock tank barrels per day.
 
Bcf.  One billion cubic feet of gas.
 
Bcfe.  One billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.
 
Brown Shales.  Fine grained rocks composed largely of clay minerals that contain little organic matter. Some of these shales immediately overlay the Marcellus Shale.
 
British Thermal Unit.  The quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.
 
CBM.  Coal bed methane.
 
Cherokee Basin.  A fifteen-county region in southeastern Kansas and northeastern Oklahoma.
 
Completion.  The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
 
Developed Acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.
 
Developed Reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Development Costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
 
Development Project.  A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
 
Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Devonian Sands.  Sands generally younger and shallower than the Marcellus Shale that occur in portions of Ohio, New York, Pennsylvania, West Virginia, Kentucky and Tennessee and generally located at depths of less than 5,000 feet.
 
Dry well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Dth.  One dekatherm, equivalent to one million British Thermal Units.


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Earned acreage.  The number of acres that has been assigned as a result of fulfilling conditions or requirements of an agreement.
 
Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
 
Exploitation.  A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
 
Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
 
Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
 
Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.
 
Farm-out.  An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.” Acreage is considered to be unearned, until the conditions of the agreement are met, and an assignment of interest has been made.
 
Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Frac/fracturing.  The method used to increase the deliverability of a well by pumping a liquid or other substance into a well under pressure to crack and prop open the hydrocarbon formation.
 
Gas.  Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.
 
Gathering system.  Pipelines and other equipment used to move gas from the wellhead to the trunk or the main transmission lines of a pipeline system.
 
Gross acres or gross wells.  The total acres or wells, as the case may be, in which we have a working interest.
 
Horizon or formation.  The section of rock, from which gas is expected to be produced.
 
Marcellus Shale.  A black, organic-rich shale formation in the Appalachian Basin that occurs in much of Ohio, West Virginia, Pennsylvania and New York and portions of Maryland, Kentucky, Tennessee and Virginia. The fairway of the Marcellus Shale is generally located at depths between 3,500 and 8,000 feet and ranges in thickness from 50 to 150 feet.
 
MBoe.  One thousand barrels of oil equivalent.
 
Mcf.  One thousand cubic feet of gas.
 
Mcf/d.  One Mcf per day.
 
Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.
 
MMbbl.  One million barrels of oil.
 
Mmbtu.  One million British Thermal Units.


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Mmcf.  One million cubic feet of gas.
 
Mmcf/d.  One Mmcf per day.
 
Mmcfe.  One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.
 
Mmcfe/d.  One million cubic feet equivalent per day.
 
Net acres or net wells.  The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
Net production.  Production that is owned by us less royalties and production due others.
 
Net revenue interest.  The percentage of revenues due an interest holder in a property, net of royalties or other burdens on the property.
 
NGLs.  Natural gas liquids being the combination of ethane, propane, butane and natural gasoline that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
 
NYMEX.  The New York Mercantile Exchange.
 
Oil.  Crude oil, condensate and NGLs.
 
Permeability.  The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies.
 
Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
Production costs.  Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced.
 
Productive well.  A well that is currently producing hydrocarbons or any exploratory, development or extension well that is reasonably believed to be capable of producing hydrocarbons.
 
Proved developed non-producing reserves.  Proved developed reserves expected to be recovered from zones behind casings in existing wells.
 
Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
 
Proved reserves.  Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience 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 — 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.
 
Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage directly offsetting development spacing areas that are reasonably certain of production when drilled, or from existing wells where a relatively major expenditure is required for recompletion.
 
Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.


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Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
 
Recompletion.  The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
 
Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.
 
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
Resources.  Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations.
 
Royalty Interest.  A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil or natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.
 
Service well.  A well drilled or completed for the purpose of supporting production in an existing field.
 
Shut in.  To close down a well temporarily.
 
Standardized measure.  The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.
 
Unconventional resource development.  A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate.
 
Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.
 
Undeveloped reserves.  Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
Unearned acreage.  The number of acres that has not yet been assigned, but may be developed per the terms of an agreement.
 
Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.


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ITEM 1A.   RISK FACTORS
 
Risks Related to Our Business
 
Our independent registered public accounting firm has expressed substantial doubt about our predecessor’s ability to continue as a going concern.
 
The independent auditor’s report accompanying our predecessor’s audited consolidated financial statements for the year ended December 31, 2009 included in this Annual Report on Form 10-K contains a statement expressing substantial doubt as to our predecessor’s ability to continue as a going concern. The factors contributing to this concern include our significant losses from 2003 through 2009, the amount of our debt obligations due during 2010 and our ability to comply with the financial covenants related to our debt facilities. If we are unable to refinance our debt, raise additional equity capital and/or complete some other strategic transaction, then we may be forced to make a bankruptcy filing or take other actions that could have a material adverse effect on our business, the price of our common stock and our results of operations, financial position and cash flows.
 
We have identified significant and pervasive material weaknesses in our internal control over financial reporting, which may persist.
 
In connection with management’s review of our internal controls as of December 31, 2009, the following control deficiencies that constituted material weaknesses related to the following items were identified:
 
  •  We did not maintain a sufficient control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. Specifically, during the first two quarters of the year, management’s attention was focused on the restatement and reaudit of prior year financial statements and the recombination, which resulted in the full implementation of our remediation plan being delayed until the third quarter of 2009. During the first two quarters of 2009, only specific identified risks related to items such as the fraud hotline, segregation of duties and cash management controls were actively monitored.
 
  •  We did not maintain sufficient monitoring controls to determine the adequacy of our internal control over financial reporting.
 
  •  We did not maintain sufficient controls over certain of our period-end financial close and reporting processes.
 
  •  We did not maintain sufficient controls to ensure completeness and accuracy of stock compensation costs.
 
  •  We did not maintain sufficient controls to ensure completeness and accuracy of depreciation, depletion and amortization expense.
 
  •  We did not maintain sufficient controls to ensure the accuracy and application of GAAP related to the impairment of oil and gas properties and, specifically, to determine, review and record oil and gas property impairments.
 
Based on the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2009.
 
These and other material weaknesses were also identified in connection with management’s review of the internal controls of QRCP and QELP as of December 31, 2008, which weaknesses resulted in the misstatement of certain of QRCP’s and QELP’s annual and interim consolidated financial statements during 2006, 2007 and 2008.
 
Additional measures may be necessary and these measures, along with other measures we expect to take to improve our internal control over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide reliable and timely financial external reports, our business and prospects could suffer material adverse effects.


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In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.
 
The recent financial crisis and current economic conditions have had, and may continue to have, a material adverse impact on our business and financial condition.
 
From the second half of 2008 through late 2009, global financial markets experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly. Also, as a result of concerns about the stability of financial markets and the solvency of counterparties, the cost of obtaining money from the credit markets increased as many lenders and institutional investors increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on more onerous terms and, in some cases, ceased to provide any new funding.
 
A continuation of current economic conditions could result in further reduced demand for oil and natural gas and put renewed downward pressure on the prices for oil and natural gas, which fell dramatically since reaching historic highs in July 2008. These price declines negatively impacted our revenues and cash flows. Difficult economic conditions could materially adversely affect our business and financial condition. For example:
 
  •  our ability to obtain credit and access the capital markets to fund the exploration or development of reserves, the construction of additional assets or the acquisition of assets or businesses from third parties may continue to be restricted;
 
  •  the counterparties to our derivative financial instrument contracts could default on their contractual obligations;
 
  •  the values we are able to realize in asset sales or other transactions we engage in to raise capital may be reduced, thus making these transactions more difficult to consummate and less economic; and
 
  •  the demand for oil and natural gas could decline due to deteriorating economic conditions, which could adversely affect our business, financial condition or results of operations.
 
No later than the first half of 2010, we will need to either refinance our debt to allow for available capital or raise a significant amount of equity capital to fund our planned drilling program and pay down outstanding indebtedness, including principal, interest and fees of approximately $21 million due under QRCP’s credit agreement on July 11, 2010. In addition, QELP is required to make principal payments on its credit facility of at least $4 million, $3 million and $4 million in the first, third and fourth quarters of 2010, respectively. We may not be able to refinance our debt or raise a sufficient amount of debt or equity capital for these purposes at the appropriate time due to market conditions or our financial condition and prospects, or we may have to incur indebtedness on unattractive terms or issue shares at a significant discount to the market price or incur debt on terms that are not favorable to us.
 
Due to these factors, funding may not be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition or cause us to file for bankruptcy. In addition, if we issue and sell additional shares in an equity offering, existing stockholders may be diluted and our stock price may decrease due to the additional shares available in the market.


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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 natural 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 current global credit and economic environment has resulted in reduced demand for natural gas and significantly lower natural gas prices. Gas prices have seen a greater percentage decline over the past twelve months than oil prices due in part to an ample supply of natural gas on the market and in storage. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. For example, during 2009, the near month NYMEX natural gas futures price ranged from a high of $6.07 per Mmbtu to a low of $2.51 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:
 
  •  the domestic and foreign supply of and demand for oil and natural gas;
 
  •  the price and level of foreign imports of oil and natural gas;
 
  •  the level of consumer product demand;
 
  •  weather conditions;
 
  •  overall domestic and global economic conditions;
 
  •  political and economic conditions in oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;
 
  •  actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
 
  •  the impact of the U.S. dollar exchange rates on oil and natural gas prices;
 
  •  technological advances affecting energy consumption;
 
  •  domestic and foreign governmental regulations and taxation;
 
  •  the impact of energy conservation efforts;
 
  •  the costs, proximity and capacity of natural gas pipelines and other transportation facilities; and
 
  •  the price and availability of alternative fuels.
 
Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices will significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:
 
  •  reduce the amount of cash flow available for capital expenditures, including for the drilling of wells and the construction of infrastructure to transport the natural gas it produces;
 
  •  negatively impact the value of our reserves because declines in oil and natural gas prices would reduce the amount of oil and natural gas we can produce economically;
 
  •  reduce the drilling and production activity of our third-party customers and increase the rate at which our customers shut in wells;
 
  •  potentially reduce natural gas available for transport on the KPC Pipeline; and
 
  •  limit our ability to borrow money or raise additional capital.


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Future price declines may result in a write-down of our asset carrying values.
 
Lower oil and natural gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and natural 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 natural 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, due to depressed natural gas prices in 2009, revisions resulting from further technical analysis and production during the year, our proved reserves decreased 57.2% to 74.8 Bcfe at December 31, 2009 from 174.8 Bcfe at December 31, 2008, and the standardized measure of our proved reserves decreased 69.2% to $50.6 million as of December 31, 2009 from $164.1 million as of December 31, 2008. The December 31, 2009 reserves were calculated using a twelve-month average price of $3.87 per Mmbtu (adjusted for basis differential, prices were $4.13 per Mmbtu in the Appalachian Basin and $3.27 per Mmbtu in the Cherokee Basin) compared to $5.71 per Mmbtu at December 31, 2008. We recognized a non-cash impairment of $102.9 million during the first quarter of 2009. At the end of the third quarter of 2009, the ceiling test computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $11.1 million. As a result of subsequent increases in spot prices, the need to recognize an impairment for the quarter ended September 30, 2009 was eliminated. No impairment was required for the quarter ended December 31, 2009. 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 recorded an impairment charge on our interstate and gathering pipelines and related contract-based intangible assets in 2009.
 
In connection with the preparation and audit of our consolidated financial statements for the year ended December 31, 2009, we recorded a non-cash impairment charge of $165.7 million on our interstate and gathering pipelines and related contract-based intangible assets in the fourth quarter of 2009. This non-cash impairment charge is due to the loss of MGE, a significant customer of the KPC Pipeline, during the fourth quarter of 2009, as well as the amendments to our credit agreements in December 2009. The amendments to our credit agreements resulted in a reduction of expected drilling activity in the Cherokee Basin. Please read “— As a result of our financial condition, we have had to significantly reduce our capital expenditures, which will ultimately reduce cash flow and result in the loss of some leases” and “— The revenues of our interstate pipeline business are generated under contracts that must be renegotiated periodically.”
 
As a result of our financial condition, we have had to significantly reduce our capital expenditures, which will ultimately reduce cash flow and result in the loss of some leases.
 
Due to the global economic and financial crisis, the decline in commodity prices, the unauthorized transfers of funds by former senior management and restrictions in our credit agreements, as described in more detail in other risk factors, we have not been able to raise the capital necessary to implement our drilling plans for 2009 and 2010. We reduced our total capital expenditures from $267.1 million in 2008 to $9.6 million in 2009. In addition, we drilled seven new wells in 2009, after completing 328 new wells in 2008. The effect of this reduced capital expenditure and drilling program is that we may not be able to maintain our reserves levels and may lose leases or other development rights that require a certain level of drilling activity. Please read “— Certain of our undeveloped acreage is subject to leases or other agreements that may expire in the near future” and “— We recorded an impairment charge on our interstate and gathering pipelines and related


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contract-based intangible assets in 2009.” During 2010, we plan to drill nine gross wells and complete 108 gross wells that were previously drilled but not completed at a total estimated cost of $26 million, but we may not be able to obtain the capital to achieve this plan.
 
We are highly leveraged.
 
As of December 31, 2009, we had approximately $372.5 million of contractual commitments outstanding, consisting of debt service requirements and operating lease commitments. We anticipate that we may in the future incur additional debt for financing our growth. 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 obtain additional debt or equity financing, if necessary, for drilling, expansion, working capital and other business needs may be impaired or such financing may not be available on favorable terms;
 
  •  a substantial decrease in our revenues as a result of lower oil and natural gas prices, decreased production or other factors could make it difficult for us to pay our liabilities. Any failure by us to meet these obligations could result in litigation, non-performance by contract counterparties or bankruptcy;
 
  •  our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make principal or interest payments on our debt;
 
  •  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
 
  •  our flexibility in responding to changing business and economic conditions may be limited.
 
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 or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.
 
There may be events of default under QRCP’s, QELP’s and QMLP’s indebtedness enabling the lenders to accelerate such indebtedness, which could lead to the foreclosure of collateral and the bankruptcy of us, QRCP, QELP and QMLP.
 
QRCP and QELP have been in default under their respective credit agreements. In May 2009, QRCP entered into an amendment to its credit agreement to, among other things, waive certain events of default related to its financial covenants and collateral requirements and to extend certain financial reporting deadlines.
 
In June 2009, QRCP, QELP and Quest Cherokee, LLC (“Quest Cherokee”) entered into amendments to their respective credit agreements that, among other things, deferred until August 15, 2009 the obligation to deliver to the Royal Bank of Canada (“RBC”), as administrative agent under the credit agreements, certain financial information. The QRCP amendment also waived financial covenant (namely the interest coverage ratio and leverage ratio) events of default for the fiscal quarter ended June 30, 2009, waived any mandatory prepayment due to any collateral deficiency during the fiscal quarter ended September 30, 2009, and deferred until September 30, 2009 the interest payment due on June 30, 2009, which amount was represented by a promissory note bearing interest at the Base Rate (as defined in QRCP’s credit agreement) with a maturity


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date of September 30, 2009. On September 11, 2009, QRCP further amended its credit agreement to extend the maturity date of the interest deferral note to July 11, 2010 while allowing interest for the third quarter of 2009, fourth quarter of 2009, first quarter of 2010 and second quarter of 2010 to be deferred to July 11, 2010 as well. The quarterly principal payments of $1.5 million due September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010 were also effectively deferred until July 11, 2010 at which time all $6 million will be due in order to satisfy certain facility fee reduction conditions. Please read “Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements — QRCP — Interest Rate and Other Fees.” Thereafter, QRCP will be required to make a principal repayment of $1.5 million at the end of each calendar quarter until maturity. If QRCP is not able to pay in full all the amounts due on July 11, 2010 (approximately $21 million), the entire amount of QRCP’s credit facility would become due and payable. QRCP may not be able to pay such amount on that date and may not be able to obtain further extensions of the maturity date.
 
An event of default under either of QELP’s credit agreements would cause an event of default under QELP’s other credit agreement.
 
If there is an event of default under any of the credit agreements, the lenders thereunder could accelerate the indebtedness and foreclose on the collateral securing that credit agreement. As of December 31, 2009, there was $35.7 million outstanding under the QRCP credit agreement, $145.0 million outstanding under the QELP credit agreement, $29.8 million outstanding under the QELP second lien loan agreement and $118.7 million under the QMLP credit agreement.
 
In July 2009, QELP’s borrowing base under its credit agreement was reduced from $190 million to $160 million. Effective December 17, 2009, QELP’s borrowing base under its credit agreement was further reduced to $145 million in connection with another borrowing base redetermination, which resulted in a borrowing base deficiency of $15 million. QELP repaid the borrowing base deficiency on December 17, 2009 in connection with the execution of the amendment to the Quest Cherokee credit agreement. QELP’s borrowing base may be further reduced in connection with future borrowing base redeterminations, which will occur on a quarterly basis beginning May 1, 2010. QELP may not be able to repay any borrowing base deficiency resulting from any future reduction in the borrowing base.
 
In addition, as a result of the recent expiration of MGE’s firm transportation contract with the KPC Pipeline and the expected decrease in 2010 in the gathering and compression fees charged under the midstream services agreement between QELP and a subsidiary of QMLP as a result of the low natural gas prices in 2009, QMLP may not be in compliance with the total leverage ratio covenant in its credit agreement commencing with the second quarter of 2010, if it is not able to reduce its expected total indebtedness as of June 30, 2010 and/or increase its anticipated EBITDA for the quarter ended June 30, 2010. If QMLP were to default, the lenders could accelerate the entire amount due under the QMLP credit agreement.
 
If QELP, QRCP or QMLP is required to pay the full amounts of its indebtedness upon acceleration, it may be able to raise the funds only by selling assets or it may be unable to raise the funds at all, in which event we may be forced to file for bankruptcy protection or liquidation.
 
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 and the terms of any future financing agreements restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. Our credit agreements and any future financings agreements may restrict our ability to:
 
  •  incur indebtedness;
 
  •  make capital expenditures above specified amounts;
 
  •  grant liens;
 
  •  pay dividends;


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  •  redeem or repurchase equity interests;
 
  •  make certain acquisitions and investments, loans or advances;
 
  •  lease equipment;
 
  •  enter into a merger, consolidation or sale of assets;
 
  •  dispose of property;
 
  •  enter into hedging arrangements with certain counterparties;
 
  •  limit the use of loan proceeds; and
 
  •  enter into transactions with affiliates, including transactions and transfers of funds among QRCP, QELP and QMLP.
 
We also are required to comply with certain financial covenants and ratios. 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.”
 
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.
 
Former senior management were terminated in 2008 following the discovery of various misappropriations of funds of QRCP and QELP.
 
In August of 2008, Jerry Cash, the former chairman, president and chief executive officer of QRCP, the general partner of QELP (“QEGP”) and the general partner of QMLP (“QMGP”), resigned and David E. Grose, the former chief financial officer of QRCP, QEGP and QMGP, was terminated, following the discovery of the misappropriation of $10 million principally from QRCP by Mr. Cash with the assistance of Mr. Grose from 2005 through mid-2008. Additionally, the Oklahoma Department of Securities has filed a lawsuit alleging that Mr. Grose and Brent Mueller, the former purchasing manager of QRCP, each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use. In March 2009, Mr. Mueller pled guilty to one felony count of misprision of justice. We have filed lawsuits against all three of these individuals seeking an asset freeze and damages related to the transfers, kickbacks and thefts. Pursuant to a settlement agreement with Mr. Cash, we recovered assets valued at $3.4 million from him and released all further claims against him. As a result of these activities, we recorded an aggregate consolidated loss of $6.6 million. We have incurred costs totaling approximately $8.5 million in connection with the investigation of these misappropriations, legal fees, accountants’ fees and other related expenses. We may not be successful in recovering any additional amounts. Any additional recoveries may consist of assets other than cash and accurately valuing such assets in the current economic climate may be difficult. Any amounts recovered will be recognized by us for financial accounting purposes only in the period in which the recovery occurs.


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QRCP and QELP are involved in securities lawsuits that may result in judgments, settlements, and/or indemnity obligations that are not covered by insurance and that may have a material adverse effect on us.
 
Between September 2008 and November 2009, four federal securities class action lawsuits, two federal individual securities lawsuits, two federal derivative lawsuits and three state court derivative lawsuits have been filed naming QRCP, QELP and certain current and former officers and directors as defendants. The securities lawsuits allege the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning the unauthorized transfers of funds by former management described above and seek class certification, money damages, interest, attorneys’ fees, costs and expenses. The complaints allege that, as a result of these actions, QRCP’s stock price and QELP’s unit price were artificially inflated. The derivative lawsuits assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets and unjust enrichment and seek disgorgement, money damages, costs, expenses and equitable or injunctive relief. Additional lawsuits may be filed. For more information, please read Part I, Item 3. “Legal Proceedings.”
 
We have incurred and will continue to incur substantial costs, legal fees and other expenses in connection with the defense against these claims. In addition, the final settlements or the courts’ final decisions in the securities cases could result in judgments against QRCP and QELP that are not covered by insurance or which exceed the policy limits. QRCP and QELP may also be obligated to indemnify certain of the individual defendants in the securities cases, which indemnity obligations may not be covered by insurance. QRCP and QELP have received letters from their directors and officers’ insurance carriers reserving their rights to limit or preclude coverage under various provisions and exclusions in the policies, including for the committing of a deliberate criminal or fraudulent act by a past, present, or future chief executive officer or chief financial officer. QELP has received a letter from its then directors’ and officers’ liability insurance carrier stating that the carrier will not provide insurance coverage to QELP based on Mr. Cash’s alleged written admission that he engaged in acts for which coverage is excluded. The carrier also reserved its rights to deny coverage under various other provisions and exclusions in the policies. QELP continues to evaluate its options regarding the insurer’s stated coverage position.
 
Following the closing of the recombination, our subsidiaries QRCP and QELP will still be parties to these lawsuits, and we now face the same risks with respect to these lawsuits as QRCP and QELP. We might not have sufficient cash on hand to fund any such payment of expenses, judgments, settlements and indemnity obligations and might be forced to file for bankruptcy or take other actions that could have a material adverse effect on our financial condition and the price of our common stock. Furthermore, certain of our officers and directors may continue to be subject to these actions for some time, which could adversely affect the ability of our management and board of directors to implement our business strategy.
 
U.S. government investigations could affect our results of operations and financial condition.
 
Numerous government entities are currently conducting investigations of QRCP, QELP and some of their former officers and directors. The Oklahoma Department of Securities has filed lawsuits against Mr. Cash, Mr. Grose and Mr. Mueller. In addition, the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies are currently conducting investigations related to QRCP and QELP and the misappropriations by these individuals.
 
We cannot anticipate the timing, outcome or possible financial or other impact of these investigations. The governmental agencies involved in these investigations have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of securities laws, and other federal and state statutes, including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. In recent years, these agencies and authorities have entered into agreements with, and obtained a broad range of penalties against, several public corporations and individuals in similar investigations, under which civil and criminal penalties were imposed, including in some cases multi-million dollar fines and other penalties and sanctions. Any injunctive relief, disgorgement, fines, penalties,


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sanctions or imposed modifications to business practices resulting from these investigations could adversely affect our results of operations and financial condition and our ability to continue as a going concern.
 
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 natural gas that we produce. The terms of some of our existing natural gas leases and other development rights may not, and the terms of some of the natural 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. In 2009, we recovered approximately 74% of the total gathering fees incurred to transport natural gas for our royalty interest owners. 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 depend on one customer for sales of substantially all our Cherokee Basin natural gas. A reduction by this customer in the volumes of gas it purchases from us could result in a substantial decline in our revenues and net income.
 
During 2009, we sold substantially all of our natural gas produced in the Cherokee Basin at market-based prices to ONEOK under a sale and purchase contract, which has an indefinite term but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. Sales under this contract accounted for approximately 61% of our consolidated revenue for 2009. If ONEOK were to reduce the volume of gas it purchases under this agreement, our revenue and cash flow could decline and our results of operations and financial condition could be materially adversely affected.
 
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 natural 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. Because of our financial condition, we were not able to replace in 2009 the reserves we produced in 2009. Similarly, we may not be able to replace in 2010 the reserves we expect to produce in 2010.


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There is a significant delay between the time we drill and complete a CBM well and when the well reaches peak production. As a result, there will be a significant lag time between when we make capital expenditures and when we will begin to recognize significant cash flow from those expenditures.
 
Our general production profile for a CBM well averages an initial 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 50-55 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when we expend capital expenditures to drill and complete a well and when we will begin to recognize significant cash flow from those expenditures may adversely affect our cash flow from operations. Our average cost to drill and complete a CBM well is between $110,000 to $125,000.
 
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 natural gas in an exact way. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of oil and natural gas that cannot be directly measured and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
 
  •  a constant level of future oil and gas prices;
 
  •  geological conditions;
 
  •  production levels;
 
  •  capital expenditures;
 
  •  operating and development costs;
 
  •  the effects of governmental regulations and taxation; and
 
  •  availability of funds.
 
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. In late 2008, the SEC adopted new rules regarding the classification of reserves that were effective for our December 31, 2009 reserve report. However, the interpretation of these rules and their applicability in different situations remains unclear in many respects. 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.”
 
In addition to proved reserves, which are those quantities of natural gas and crude oil that can be estimated with reasonable certainty to be economically producible within the time period provided by applicable SEC rules, we disclose in this annual report our “probable” and “possible” reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves include additional reserves that are less certain to be recovered than probable reserves. These estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by us.
 
Our standardized measure is calculated using unhedged oil and natural 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


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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 natural gas properties also will be affected by factors such as:
 
  •  the actual prices we receive for oil and natural gas;
 
  •  our actual operating costs in producing oil and natural gas;
 
  •  the amount and timing of actual production;
 
  •  the amount and timing of our capital expenditures;
 
  •  supply of and demand for oil and natural gas; and
 
  •  changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows 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 natural 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 natural 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:
 
  •  high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
 
  •  adverse weather conditions;
 
  •  difficulty disposing of water produced as part of the coal bed methane production process;
 
  •  equipment failures or accidents;
 
  •  title problems;
 
  •  pipe or cement failures or casing collapses;
 
  •  compliance with environmental and other governmental requirements;
 
  •  environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
 
  •  lost or damaged oilfield drilling and service tools;
 
  •  loss of drilling fluid circulation;
 
  •  unexpected operational events and drilling conditions;
 
  •  increased risk of wellbore instability due to horizontal drilling;
 
  •  unusual or unexpected geological formations;
 
  •  natural disasters, such as fires and floods;
 
  •  blowouts, surface craterings and explosions; and
 
  •  uncontrollable flows of oil, gas or well fluids.


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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 natural 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 natural 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.
 
We have less information regarding reserves and decline rates in the Marcellus Shale than in the Cherokee Basin. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the Cherokee Basin.
 
As of December 31, 2009, we had drilled two vertical, completed one vertical and drilled and completed two horizontal gross wells in the Marcellus Shale. We have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in the Cherokee Basin. The wells to be drilled in the Marcellus Shale will be drilled deeper than in the Cherokee Basin and some may be horizontal wells, which makes the Marcellus Shale wells more expensive to drill and complete. The wells, especially any horizontal wells, are also more susceptible than those in the Cherokee Basin to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale is more extensive and complicated than fracturing the geological formations in the Cherokee Basin and requires greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.
 
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. Please read “— We recorded an impairment charge on our interstate and gathering pipelines and related contract-based intangible assets in 2009.” KGS has several contracts for firm capacity on the KPC Pipeline, including contracts for the following capacities and terms (i) 12,000 Dth/d extending through October 31, 2013, (ii) 57,568 Dth/d extending through October 31, 2017, (iii) 6,857 Dth/d extending through March 31, 2017 and (iv) 6,900 Dth/d extending through September 30, 2017. We executed new letter agreements with KGS covering 27,568 Dth/d and 30,000 Dth/d (total of 57.568 Dth/d), both of which would extend through October 31, 2017. The contract for 30,000 Dth/d has provisions for volume decreases after the third year on a sliding basis each year.
 
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:
 
  •  competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity in markets served by our interstate pipelines;
 
  •  changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;
 
  •  reduced demand and market conditions in the areas we serve;


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  •  the availability of alternative energy sources or natural gas supply points; and
 
  •  regulatory actions.
 
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 oil and natural gas 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 oil and natural gas 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 natural 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 we enter into derivative transactions related to only a portion of our expected production volumes and, 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:
 
  •  a counterparty may not perform its obligation under the applicable derivative instrument;
 
  •  there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
 
  •  the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.
 
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 and Appalachian Basin. As a result, our business is disproportionately exposed to adverse developments affecting these regions. These 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 these operating areas 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 natural 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


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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 natural 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 natural 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 natural gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and natural 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 our Cherokee Basin gas gathering system, we may face competition in our efforts to obtain additional natural gas volumes. We will compete principally against other producers in the Cherokee Basin with natural gas gathering services. Our competitors may expand or construct gathering systems in the Cherokee Basin that would create additional competition for the services we provide to our customers.
 
With respect to the KPC 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 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 PipeLine 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:
 
  •  damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
 
  •  inadvertent damage from construction, farm and utility equipment;
 
  •  leaks of gas or oil spills as a result of the malfunction of equipment or facilities;
 
  •  fires and explosions; and
 
  •  other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
 
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


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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.
 
Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production and adversely affect our results of operations.
 
Wage increases and shortages in personnel in the future could increase our costs and/or restrict or delay our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and could reduce our revenue and cash flow. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented or cause existing wells to become shut-in, reducing our production and adversely affecting our 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, 2009, we held oil and gas leases on approximately 516,184 net acres, of which 124,180 net acres (or 24%) 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 75,621 net acres are scheduled to expire before December 31, 2010. If these leases expire and are not renewed, we will lose the right to develop the related properties.
 
We hold oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on 29,877 net acres in the Appalachian Basin 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. We are currently required to drill three gross gas wells by April 30, 2010 in order to maintain approximately 2,000 net acres. We must also drill an additional three gross gas wells by December 31, 2010 to maintain approximately an additional 6,000 net acres. Furthermore, we are currently required to drill an additional four gross wells in order to maintain 1,605 net acres in New York. The exact deadline for the drilling of these four wells is currently unclear, due to permitting delays caused by an environmental impact review being conducted by the state of New York. We may not be able to meet the drilling and payment obligations to earn or maintain all of this leasehold acreage.
 
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 as of December 31, 2009, approximately 590 gross proved undeveloped drilling locations and approximately 1,063 additional gross potential drilling locations in the Cherokee Basin and approximately 25 gross proved undeveloped drilling locations and approximately 415 additional gross potential drilling locations in the Appalachian 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, 2009 reserve


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report. In addition, no proved reserves are assigned to any of the approximately 1,063 Cherokee Basin and 415 Appalachian Basin potential drilling locations we have identified and therefore, there exists greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. 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 oil or gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and gas leases, or undivided interests in oil and gas 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 oil and gas 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 an oil or gas well, however, it is the normal practice in the oil and gas 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 oil or gas 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 natural 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. However, 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. In addition, 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.
 
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


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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.
 
Third-party producers on our Cherokee Basin gathering system have the ability to file complaints challenging the rates that we charge. The rates must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the 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 the rates with respect to the wells that were the subject of the complaint. Our gathering operations also 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.
 
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.
 
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:
 
  •  transportation of natural gas;
 
  •  rates, operating terms and conditions of service;
 
  •  the types of services KPC may offer to its customers;
 
  •  construction of new facilities;
 
  •  acquisition, extension or abandonment of services or facilities;
 
  •  accounting and recordkeeping;
 
  •  commercial relationships and communications with affiliated companies involved in certain aspects of the natural gas business; and
 
  •  the initiation and discontinuation of services.
 
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. Specifically, FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group 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.


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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.
 
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 Energy Policy Act of 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 Energy Policy Act of 2005, FERC has initiated a number of enforcement proceedings and imposed penalties on various regulated entities, including other interstate natural gas pipelines.
 
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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, liability for natural resource damages or damages to third parties, and to a lesser extent, issuance of injunctions to limit or cease operations.
 
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 impose requirements for the handling, storage, treatment or discharge of waste from our facilities, (4) 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 to which we or our predecessors have 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


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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:
 
  •  we cannot obtain future permits from applicable regulatory agencies;
 
  •  water of lesser quality or requiring additional treatment is produced;
 
  •  our wells produce excess water;
 
  •  new laws and regulations require water to be disposed in a different manner; or
 
  •  costs to transport the produced water to the disposal wells increase.
 
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 U.S. Environmental Protection Agency (“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:
 
  •  perform ongoing assessments of pipeline integrity;
 
  •  identify and characterize applicable threats to pipeline segments that could impact a high consequence area;


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  •  improve data collection, integration and analysis;
 
  •  repair and remediate the pipeline as necessary; and
 
  •  implement preventive and mitigating actions.
 
We incurred costs of approximately $0.2 million in 2009 to complete all baseline assessments of the covered high consequence area integrity testing. We estimate we will incur approximately $1.5 million in 2010 to implement pipeline integrity management program testing along certain segments of natural gas pipelines. We also incurred costs of approximately $0.4 million in 2009 and expect to incur additional costs in 2010 to complete the last year of a Stray Current Survey resulting from a 2005 DOT audit. These costs may be significantly higher than what we have estimated or previously incurred due to the following factors:
 
  •  our estimate does not include the costs of repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial;
 
  •  additional regulatory requirements that are enacted could significantly increase the amount of these expenditures;
 
  •  the actual implementation costs may be materially higher than our estimates because of increased industry-wide demand for contractors and service providers and the related increase in costs; or
 
  •  failure to comply with DOT regulations and any corresponding deadlines, which could subject us to penalties and fines.
 
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 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. Specifically, in December 2009, EPA published a final rule, also known as the Endangerment Finding, finding that GHGs in the atmosphere endanger public health and welfare, and that emissions of GHGs from mobile sources cause or contribute to the GHG pollution. The Endangerment Finding took effect on January 14, 2010 and allows EPA to promulgate motor vehicle GHG emission standards. EPA is expected to promulgate such standards in March 2010. Motor vehicle emission standards could impact our operations by effectively reducing demand for motor fuels from crude oil. In addition, EPA has asserted that final motor vehicle GHG emission standards will trigger construction and operating permit requirements for large stationary sources, which could affect our operations and our ability to obtain air permits for new or modified facilities. Similarly, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The U.S. Senate is working on its own legislation for controlling and reducing emissions of GHGs in the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur capital expenditures and increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce. At the state level, more than one-third of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. The California Global Warming Solutions Act of 2006, also known as “AB 32,” caps California’s greenhouse gas emissions at 1990 levels by 2020, and the California Air Resources Board is currently developing mandatory reporting regulations and early action measures to reduce GHG emissions prior to January 1, 2012. Although most of the regulatory initiatives developed or being developed by the various states have to date been focused on large sources of GHG emissions, such as coal-fired electric power plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations in the future.


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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.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production in unconventional plays, which could adversely impact our revenues.
 
Congress is currently considering legislation to amend the SDWA to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells in the Appalachian Basin and specifically the Marcellus Shale. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level. This could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for us to perform hydraulic fracturing and increase our costs of compliance and doing business.
 
Growing our business by constructing new assets is subject to regulatory, political, legal and economic risks.
 
One of the ways we intend to grow our business in the long-term is through the construction of new midstream assets.
 
The construction of additions or modifications to our gas gathering systems and/or the KPC Pipeline, and the construction of new midstream assets, involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things:
 
  •  inability to complete construction of these projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials;
 
  •  failure to receive any material increases in revenues until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;
 
  •  facilities may be constructed to capture anticipated future growth in production in a region in which such growth does not materialize;
 
  •  reliance on third-party estimates of reserves in making a decision to construct facilities, which estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves;
 
  •  inability to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical;
 
  •  the construction of additions or modifications to the KPC Pipeline may require the issuance of certificates of public convenience and necessity from FERC, which may result in delays or increased costs; and
 
  •  additions to or modifications of our gas gathering systems could result in a change in their NGA-exempt status.


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Our ability to grow and to increase our profitability depends in part on our ability to make acquisitions. Our acquisition strategy is subject to a number of risks.
 
Our ability to grow and to increase our profitability depends 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 nevertheless result in a decrease in net income and/or cash flows. Any acquisition involves potential risks, including, among other things:
 
  •  mistaken assumptions about reserves, future production, volumes, revenues and costs, including synergies;
 
  •  an inability to integrate successfully the businesses we acquire;
 
  •  a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
 
  •  a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;
 
  •  the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
 
  •  an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
 
  •  limitations on rights to indemnity from the seller;
 
  •  mistaken assumptions about the overall costs of equity or debt;
 
  •  the diversion of management’s and employees’ attention from other business concerns;
 
  •  the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
 
  •  unforeseen difficulties operating in new product areas or new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
 
In addition, we may pursue acquisitions outside the Cherokee and Appalachian Basins. Because we operate substantially in the Cherokee and Appalachian Basins, we do not have the same level of experience in other basins. Consequently, acquisitions in areas outside the Cherokee and Appalachian Basins may not allow us the same operational efficiencies we benefit from in those basins. In addition, acquisitions outside the Cherokee and Appalachian Basins expose us to different operational risks due to potential differences, among others, in:
 
  •  geology;
 
  •  well economics;
 
  •  availability of third-party services;
 
  •  transportation charges;


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  •  content, quantity and quality of oil and gas produced;
 
  •  volume of waste water produced;
 
  •  state and local regulations and permit requirements; and
 
  •  production, severance, ad valorem and other taxes.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.
 
If third-party pipelines and other facilities interconnected to our natural gas pipelines become unavailable to transport or produce natural gas, our revenues and cash available for distribution 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 natural gas, our revenues and cash available for distribution could be adversely affected.
 
Failure of the natural 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.
 
Natural gas gathered on our gas gathering systems is delivered into interstate pipelines. These interstate pipelines establish specifications for the natural 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 natural gas delivered from our gas gathering systems fails to meet the specifications of a particular interstate pipeline that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, we may be required to find alternative markets for that natural gas or to shut-in the producers of the non-conforming natural gas, potentially reducing our throughput volumes and revenues.
 
Our interstate natural gas pipeline has recorded certain assets that may not be recoverable from our customers.
 
FERC rate-making and accounting policies permit pipeline companies to record certain types of expenses that relate to regulated activities to be recorded on our balance sheet as regulatory assets for possible future recovery in jurisdictional rates. We consider a number of factors to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable or if FERC denies recovery, we would be required to write off the regulatory assets at that time, potentially reducing our revenues.
 
Operational limitations of the KPC Pipeline could cause a significant decrease in our revenues and operating results.
 
During peak demand periods, failures of compression equipment or pipelines could limit the KPC Pipeline’s ability to meet firm commitments, which may limit our ability to collect reservation charges from our customers and, if so, could negatively impact our revenues and results of operations.


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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 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 may experience volatility.
 
The price of our common stock may 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.


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We do not expect to pay dividends on our common stock for the foreseeable future.
 
We do not expect to pay dividends 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.
 
The value of the shares of our common stock may be diluted by future equity issuances.
 
No later than the first half of 2010, we will need to either refinance our debt to allow for available capital or raise a significant amount of equity capital to fund our drilling program and pay down outstanding indebtedness, including principal, interest and fees of approximately $21 million due under QRCP’s credit agreement on July 11, 2010. Such issuance and sale of equity could be dilutive to the interests of our existing stockholders and reduce the market price of our common stock.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS.
 
None.
 
ITEM 2.   PROPERTIES.
 
We have described our oil and natural gas properties, oil and natural gas 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, Suite 2750, 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 administrative offices, a geological laboratory, an operations terminal and a repair facility. We own an additional building and storage yard in Lenapah, Oklahoma.
 
Our subsidiary Quest Eastern Resource LLC (“Quest Eastern”) has leased approximately 4,744 square feet of office space located at 2200 Georgetowne Drive, Suite 301, Sewickley, Pennsylvania 15143. Since administrative duties have been transferred to Oklahoma City, Quest Eastern is actively pursuing a sub-lease tenant for the remaining term of its lease, which expires on August 1, 2013. Quest Eastern also owns a 50% interest in a nine acre lot with building improvements in Wetzel County, West Virginia that is used for equipment storage and office space and leases approximately 1,500 square feet of office space for field personnel in Harrisville, West Virginia under an annual lease expiring on August 31, 2010.
 
We have 9,801 square feet of leased office space for some of our personnel located at 3 Allen Center, 333 Clay Street, Suite 4060, Houston, Texas 77002. 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, 2010. The Medicine Lodge field office is leased on a month-to-month basis.
 
ITEM 3.   LEGAL PROCEEDINGS.
 
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 following litigation. We intend to defend vigorously against the claims described below. We are unable to predict the outcome of these proceedings or reasonably estimate a


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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 Securities Class Actions
 
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 putative class action complaints were filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP and 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 was artificially inflated during the class period. On December 29, 2008, the court consolidated these complaints as 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, in the Western District of Oklahoma. On September 24, 2009, the court appointed lead plaintiffs for each of the QRCP class and the QELP class. On October 13, 2009, the plaintiffs filed a motion for partial modification of PSLRA discovery stay, which the defendants opposed and which the court denied on December 15, 2009. On November 4, 2009, the court granted the lead plaintiffs’ unopposed request to file separate consolidated amended complaints. The court ordered that all pleadings and filings for the QELP class be filed under Friedman v. Quest Energy Partners, LP, et al., case no. CIV-08-936-M, and all pleadings and filings for the QRCP class be filed under Jents v. Quest Resource Corporation, et al., case no. CIV-08-968-M. The QELP lead plaintiffs filed a consolidated complaint on November 10, 2009. The consolidated complaint names as additional defendants David C. Lawler, Gary Pittman, Mark Stansberry, Murrell Hall, McIntosh & Co. PLLP, and Eide Bailly LLP. The QRCP lead plaintiffs filed a consolidated complaint on December 7, 2009, which names Murrell, Hall, McIntosh & Co. PLLP, Eide Bailly LLP, and various former QRCP directors as additional defendants. On December 23, 2009, QRCP and David C. Lawler filed a motion to dismiss the Friedman complaint, and on December 28, 2009, QELP, QEGP, Gary Pittman and Mark Stansberry filed a motion to dismiss the Friedman complaint. On January 21, 2010, QRCP and the individual director defendants filed a motion to dismiss the Jents complaint. No response to the motion to dismiss has yet been filed in either proceeding. On February 2, 2010, a mediation was held among the parties. A second round of the mediation is currently scheduled for April 2, 2010. In the event that the cases are not settled, then the companies intend to defend vigorously against the plaintiffs’ claims in both the Friedman and Jents actions.


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QRCP and QELP have received letters from their directors and officers’ insurance carriers reserving their rights to limit or preclude coverage under various provisions and exclusions in the policies, including for the committing of a deliberate criminal or fraudulent act by a past, present, or future chief executive officer or chief financial officer. On October 27, 2009, QELP received written confirmation from its directors’ and officers’ liability insurance carrier stating that it will not provide insurance coverage to QELP based on Mr. Cash’s alleged written admission that he engaged in acts for which coverage is excluded. The carrier also reserved its rights to deny coverage under various other provisions and exclusions in the policies. QELP disagrees with the insurance carrier’s coverage position and continues to evaluate its options regarding the same.
 
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. Plaintiffs have agreed to participate in the April 2, 2010 mediation mentioned above in connection with the federal securities class actions. QRCP intends to defend vigorously against the plaintiff’s claims.
 
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. QRCP and QELP intend to defend vigorously against the plaintiffs’ claims. Plaintiffs have agreed to participate in the April 2, 2010 mediation mentioned above in connection with the federal securities class actions.


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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 purported 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 October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. Proceedings in this matter are currently stayed. QRCP intends to defend vigorously against these claims.
 
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-F, 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 QELP to take all necessary actions to reform and improve its corporate governance and internal procedures. On September 8, 2009, the case was transferred to Judge Miles-LaGrange, who is presiding over the other federal cases, and the case number was changed to CIV-09-752-M. All proceedings in this matter are currently stayed under Judge Miles-LaGrange’s order of October 16, 2009. QELP intends to defend vigorously against these claims.
 
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 purported 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


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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 Messrs. Cash’s and 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. Under the court’s order, the defendants need not respond to the individual petitions. The action is stayed by agreement of the parties until the motions to dismiss in the pending federal securities class action litigation are decided. QRCP intends to defend vigorously against plaintiffs’ claims.
 
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
 
Quest Cherokee, a wholly-owned subsidiary of QELP, was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee has answered the complaint and denied plaintiffs’ claims. On July 21, 2009, the court granted plaintiffs’ motion to compel production of Quest Cherokee’s electronically stored information, or ESI, and directed the parties to decide upon a timeframe for producing Quest Cherokee’s ESI. Discovery was stayed until April 14, 2010 to allow the parties to discuss settlement terms.
 
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
 
QRCP et al. have been named in the above-referenced lawsuit. Plaintiffs are royalty owners who allege that the defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts resulting in less than market price for the gas production. Plaintiffs pray for unspecified actual and punitive damages. The defendants have filed a motion to dismiss certain tort claims, but no ruling has yet been issued by the Court. Limited pretrial discovery has occurred. No court deadlines have been set. QRCP intends to defend vigorously against the plaintiffs’ claims.


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
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. There were no daily high and low sales prices per share or cash distributions to PostRock stockholders during 2009 or 2008. The closing price for our common stock on March 8, 2010 was $16.36 per share.
 
As of March 8, 2010, there were 8,029,898 shares of common stock outstanding held of record by approximately 672 stockholders.
 
Dividends
 
The payment of dividends on our common stock is within the discretion of the board of directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. We have not declared any cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future. Our ability to pay dividends on our common stock is subject to restrictions contained in our credit agreements. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” for a discussion of these restrictions.
 
Unregistered Sales of Equity Securities
 
None.
 
Issuer Purchases of Equity Securities
 
None.


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ITEM 6.   SELECTED FINANCIAL DATA (PREDECESSOR).
 
We have derived the following selected consolidated financial information as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, from the audited consolidated financial statements of QRCP (predecessor to PostRock) included in Part II, Item 8 of this Annual Report on Form 10-K. We have derived the selected consolidated financial information as of December 31, 2007, 2006 and 2005 and for the years ended December 31, 2006 and 2005 from the consolidated financial information of QRCP included in QRCP’s annual report on Form 10-K/A for the year ended December 31, 2008 recasted to conform with the presentation requirements of FASB ASC 810 regarding noncontrolling interests. The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and the audited consolidated financial statements and related notes included in Part II, Item 8 of this Annual Report on Form 10-K.
 
                                         
    Years Ended December 31,  
    2009     2008     2007     2006     2005  
    (In thousands, except share and per share data)  
 
Statement of Operations Data:
                                       
Revenues:
                                       
Oil and gas sales
  $ 79,893     $ 162,499     $ 105,285     $ 72,410     $ 70,628  
Gas pipeline revenue
    26,188       28,176       9,853       5,014       3,939  
                                         
Total revenues
    106,081       190,675       115,138       77,424       74,567  
Costs and expenses:
                                       
Oil and gas production
    33,451       44,111       36,295       25,338       18,532  
Pipeline operating
    29,083       29,742       21,098       13,151       7,703  
General and administrative
    41,723       28,269       21,023       8,655       6,218  
Depreciation, depletion and amortization
    47,802       70,445       39,782       27,011       22,244  
Impairments
    268,630       298,861                    
Loss (Recovery) from misappropriation of funds
    (3,412 )           2,000       6,000       2,000  
                                         
Total costs and expenses
    417,277       471,428       120,198       80,155       56,697  
                                         
Operating income (loss)
    (311,196 )     (280,753 )     (5,060 )     (2,731 )     17,870  
Other income (expense):
                                       
Gain (loss) from derivative financial instruments
    48,122       66,145       1,961       52,690       (73,566 )
Gain (loss) on sale of assets
          24       (322 )     3       12  
Loss on early extinguishment of debt
                            (12,355 )
Other income (expense)
    83       305       (9 )     99       389  
Interest expense, net
    (29,329 )     (25,373 )     (43,628 )     (20,567 )     (28,225 )
                                         
Total other income and (expense)
    18,876       41,101       (41,998 )     32,225       (113,745 )
                                         
Income (loss) before income taxes
    (292,320 )     (239,652 )     (47,058 )     29,494       (95,875 )
Income tax benefit (expense)
                             
                                         
Net income (loss)
    (292,320 )     (239,652 )     (47,058 )     29,494       (95,875 )
Net loss attributable to noncontrolling interests
    147,398       72,268       2,904       14        
                                         
Net income (loss) attributable to common stockholders
    (144,922 )     (167,384 )     (44,154 )     29,508       (95,875 )
Preferred stock dividends
                            (10 )
                                         
Net income (loss) available to common shareholders
  $ (144,922 )   $ (167,384 )   $ (44,154 )   $ 29,508     $ (95,885 )
                                         
Net income (loss) available to common shareholders per share:
                                       
Basic and diluted
  $ (4.55 )   $ (6.20 )   $ (1.97 )   $ 1.33     $ (11.48 )
Weighted average common and common equivalent shares outstanding:
                                       
Basic and diluted
    31,833,222       27,010,690       22,379,479       22,119,497       8,351,945  
                                         
Balance Sheet Data (at end of period):
                                       
Total assets
  $ 283,655     $ 650,176     $ 672,537     $ 467,936     $ 274,768  
Long-term debt, net of current maturities
  $ 19,295     $ 343,094     $ 233,046     $ 225,245     $ 100,581  


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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, (3) the formation of QMLP in December 2006, (4) the acquisition of the KPC Pipeline on November 1, 2007, (5) QELP’s initial public offering effective November 15, 2007, (6) the PetroEdge acquisition in July 2008, (7) investigation and litigation costs associated with the misappropriation by our former chief executive officer and chief financial officer in 2008 and 2009, (8) expenses related to the recombination in 2009 and (9) impairment of oil and gas 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 pipelines of $165.7 million in 2009.
 
ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
 
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 set forth in Part I, Item 1A of this Annual Report on Form 10-K.
 
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 natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.
 
When we use the words “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:
 
  •  current weak economic conditions;
 
  •  our current financial condition and liquidity constraints;
 
  •  volatility of oil and natural gas prices;
 
  •  benefits or effects of the recombination;
 
  •  increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
 
  •  our restrictive debt covenants;
 
  •  access to capital, including debt and equity markets;
 
  •  results of our hedging activities;
 
  •  drilling, operational and environmental risks; and
 
  •  regulatory changes and litigation risks.
 
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.


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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.
 
Overview of Our Company
 
We are a Delaware corporation formed on July 1, 2009 solely for the purpose of effecting a recombination of QRCP, QELP and QMLP. Prior to the consummation of the recombination on March 5, 2010, we did not conduct any business operations other than incidental to our formation and in connection with the transactions contemplated by the merger agreement for the recombination. Following the recombination, we own QRCP, QELP and QMLP as direct or indirect wholly-owned subsidiaries and have no significant assets other than the stock and other voting securities of our subsidiaries.
 
We are an integrated independent energy company involved in the acquisition, development, exploration, production and transportation of natural gas, primarily from coal seams (coal bed methane, or “CBM”) and unconventional shale, and oil and natural gas from conventional reservoirs. We conduct our business through two reportable business segments:
 
  •  Oil and natural gas production, and
 
  •  Natural gas pipelines, including transporting, gathering, treating and processing natural gas.
 
Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma; Central Oklahoma; and West Virginia, Pennsylvania and New York in the Appalachian Basin. Our primary assets, as of December 31, 2009, consisted of natural gas wells, oil wells, development rights and natural gas gathering pipelines in the Cherokee Basin and Appalachian Basin, oil and natural gas wells and development rights in Central Oklahoma, and an interstate natural gas pipeline that transports natural gas from northern Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets.
 
Operating Highlights
 
Our significant operational highlights in 2009 include:
 
  •  Reduced oil and natural gas production costs to $1.54 per Mcfe (including production and property taxes of $0.35 per Mcfe) in 2009 from $2.03 per Mcfe (including production and property taxes of $0.45 per Mcfe) in 2008, which reduced operating costs by $10.6 million.
 
  •  Sustained a production level of 21.7 MMcfe in 2009 despite minimal current period capital expenditures on acquisition and development.
 
Cost-cutting Measures.
 
We successfully reduced our operating costs in 2009 through the implementation of process improvement initiatives. These initiatives support our efficient operating model that seeks to generate the highest production possible for the lowest sustainable cost. In addition to process improvement initiatives, we have employed the latest artificial lift technology in order to improve equipment reliability and minimize costly wellbore interventions. We have also optimized our compression fleet to decrease fuel consumption and improve horsepower utilization. We periodically evaluate all aspects of our operation to further reduce our costs.


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Material Events and Transactions
 
The following events or transactions impacted our results of operations in 2009:
 
Pipeline segment impairment
 
Certain events during the fourth quarter of 2009 indicated our pipeline assets and intangibles could be impaired. We were unable to negotiate a new contract with one of our major customers for the KPC Pipeline, MGE. Our existing contract with MGE expired in October 2009, although prior to the expiration we believed that the contract could be extended or renegotiated with MGE or replaced by another customer. In addition, while we were successful in negotiating amendments to our credit facilities in December 2009, the amended credit facilities imposed limits 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.
 
Based on our analysis, we determined that the carrying value of our pipeline assets exceeded their fair values by approximately $164.7 million and recorded an impairment for such amount in the fourth quarter of 2009. In addition, we determined that our customer-related contracts, held by KPC and presented as intangible assets on the balance sheet, were also impaired. We recognized an impairment of $1.0 million on our intangible assets. No such impairment was required at December 31, 2008.
 
Oil and natural gas impairment
 
Prior to December 31, 2009, full cost accounting rules required us to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. Beginning with this annual report, a twelve-month average is now used. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. At the end of the first quarter of 2009, we recorded a ceiling test impairment of $102.9 million. At the end of the third quarter of 2009, the ceiling test computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $11.1 million. As a result of subsequent increases in spot prices, the need to recognize an impairment for the quarter ended September 30, 2009 was eliminated. No further impairment was necessary for the remainder of 2009.
 
Settlement of misappropriation
 
In May 2009, QRCP, QELP and QMLP entered into settlement agreements with Mr. Cash, a controlled entity of Mr. Cash and the other owners of the controlled entity to settle litigation related to the misappropriation of funds discussed under Part I, Item 1A. “Risk Factors — Risks Related to Our Business — Former senior management were terminated in 2008 following the discovery of various misappropriations of funds of QRCP and QELP.” Under the terms of the settlement agreements, we received (1) approximately $2.4 million in cash and (2) 60% of the controlled entity’s interest in a natural gas well located in Louisiana and a landfill natural gas development project located in Texas. We also received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for costs of the internal investigation and the litigation against Mr. Cash that we have paid. We have estimated the fair value of the assets and liabilities obtained in connection with the settlement to be $3.4 million.
 
Increased Costs
 
We experienced significant increased general and administrative costs in 2009 due to various factors, such as the internal investigation and our responding to inquiries with respect to the misappropriation of funds by our former chief executive officer and chief financial officer. As a result of the termination of the former chief executive officer and chief financial officer, we retained consultants to perform the accounting and finance functions. We incurred legal expenses in connection with responses to the class action and derivative suits that have been filed against us and to pursue the claims against the former employees. Our audit expenses were


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higher as a result of retaining new auditors to complete reaudits of the restated consolidated financial statements for the years ended December 31, 2007, 2006 and 2005. In connection with our recombination, we retained financial advisors, accountants, other consultants and outside legal counsel as well as incurred other costs related to the SEC registration process and the shareholder and unitholder meetings to approve the recombination. These activities contributed to the increase in our general and administrative costs by approximately $13.4 million in 2009 compared to 2008.
 
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 include the following: (1) volumes of gas and oil produced; (2) quantity of proved reserves; (3) realized prices; (4) throughput volumes, firm transportation contracted volumes, fuel consumption by our facilities and natural gas sales volumes; (5) operations and maintenance expenses; and (6) oil and gas production and general and administrative expenses.
 
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 $4.06 per Mcf in 2009, and the forecast price averages $5.36 per Mcf in 2010 and $6.12 per Mcf in 2011. Continued high storage levels, combined with enhanced domestic production capabilities and slow consumption growth, are expected to keep prices from rising dramatically through the forecast.
 
Oil and natural gas prices historically have been very volatile and will likely continue to be so in the future. While natural gas inventories remain ample, implied volatility for the futures market in natural gas options moved slightly higher at the start of 2010. Implied volatility for options settling against March 2010 natural gas futures averaged just below 57%, similar to the prior year when implied volatility on the March 2009 natural gas options was at 59%.
 
We sell the majority of our natural 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 2009, the discount (or basis differential) in the Cherokee Basin ranged from $0.05/Mmbtu to $(1.37)/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 Natural Gas
 
The EIA estimates that total natural gas consumption fell by 1.5 percent in 2009, primarily because of the economic downturn. Despite low natural gas prices throughout most of 2009, which contributed to a significant increase in natural gas-fired electric power generation, declines in industrial, residential, and commercial sector consumption drove the year-over-year decline in total consumption. Total annual natural gas consumption is forecast to remain relatively unchanged in 2010. Higher natural gas prices in 2010 are expected to cause a 2.8 percent decline in natural gas consumption in the electric power sector in 2010, which will offset growth in the residential, commercial, and industrial sectors. Forecast total natural gas consumption increases by 0.4 percent in 2011, led by a 2.5 percent increase in consumption in the industrial sector.


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The world oil market is expected to gradually tighten in 2010 and 2011, provided the global economic recovery continues as projected. Although compliance with cuts announced by the Organization of the Petroleum Exporting Countries (OPEC) has weakened and global oil inventories and spare production capacity remain very high by historical standards, expectations of a continued global economic turnaround have continued to buttress oil markets. Global oil demand declined in 2009 for the second consecutive year. The decline bottomed out in the middle of 2009, as the world economy began to recover in the last half of the year. EIA expects this recovery to continue in 2010 and 2011, contributing to global oil demand growth of 1.1 million barrels per day (Bbl/d) in 2010 and 1.5 million Bbl/d in 2011. In the United States, projected demand is expected to increase slightly by 0.2 million Bbl/d after a very weak 2009.
 
Capital Constraints
 
Due to 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 have not been able to raise the capital necessary to implement our drilling plans for 2009 and 2010. For 2010, we have budgeted approximately $6.0 million to complete and $5.5 million to connect 108 gross wells that were previously drilled but not completed, and $2.7 million for land and equipment in the Cherokee Basin. In the Appalachian Basin, for 2010 we have budgeted approximately $20 million of net expenditures to drill and complete three vertical wells and six horizontal wells and $2.5 million on land, equipment and connections. We intend to fund these capital expenditures with available cash from operations after taking into account our debt service obligations and with the proceeds of additional equity capital issuances and borrowings, but there can be no assurance that we will be able to obtain the capital to achieve this plan.
 
Results of Operations
 
The following discussion of results of operations should be read in conjunction with the audited consolidated financial statements and the notes to the consolidated financial statements of the predecessor, which are included elsewhere in this Annual Report on Form 10-K.
 
                         
    2009     2008     2007  
    (In thousands)  
 
Revenues:
                       
Oil and gas production
  $ 79,893     $ 162,499     $ 105,285  
Natural gas pipelines
    67,323       63,722       39,032  
Elimination of inter-segment revenue
    (41,135 )     (35,546 )     (29,179 )
                         
Natural gas pipelines, net of inter-segment revenue
    26,188       28,176       9,853  
                         
Total segment revenues
  $ 106,081     $ 190,675     $ 115,138  
                         
Operating profit (loss):
                       
Oil and gas production(a)
  $ (129,788 )   $ (269,729 )   $ 5,999  
Natural gas pipelines(b)
    (143,097 )     17,245       11,964  
                         
Total segment operating profit (loss)
    (272,885 )     (252,484 )     17,963  
General and administrative expenses
    41,723       28,269       21,023  
Loss (Recovery) from misappropriation of funds
    (3,412 )           2,000  
                         
Total operating income (loss)
  $ (311,196 )   $ (280,753 )   $ (5,060 )
                         
 
 
(a) Includes impairment of oil and gas properties of $102.9 million and $298.9 million in 2009 and 2008, respectively.
 
(b) Includes impairment of pipeline related assets of $165.7 million in 2009.


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Year ended December 31, 2009 compared to the year ended December 31, 2008
 
Oil and Gas Production Segment
 
                                 
    Year Ended
             
    December 31,     Increase/
 
    2009     2008     (Decrease)  
    ($ in thousands)  
 
Oil and gas sales
  $ 79,893     $ 162,499     $ (82,606 )     (50.8 )%
Oil and gas production costs
  $ 33,451     $ 44,111     $ (10,660 )     (24.2 )%
Transportation expense (intercompany)
  $ 41,135     $ 35,546     $ 5,589       15.7 %
Depreciation, depletion and amortization
  $ 32,193     $ 53,710     $ (21,517 )     (40.1 )%
Impairment charge of oil and natural gas properties
  $ 102,902     $ 298,861     $ (195,959 )     (65.6 )%
 
Production.  The following table presents the primary components of revenues of our Oil and Gas Production Segment (oil and natural gas production and average oil and natural gas prices), as well as the average costs per Mcfe, for the fiscal years ended December 31, 2009 and 2008.
 
                                 
    Year Ended December 31,     Increase/
 
    2009     2008     (Decrease)  
 
Production Data:
                               
Total production (Mmcfe)
    21,733       21,748       (15 )     (0.1 )%
Average daily production (Mmcfe/d)
    59.5       59.4       0.1       0.2 %
Average Sales Price per Unit (Mcfe)
  $ 3.68     $ 7.47     $ (3.79 )     (50.7 )%
Average Unit Costs per Mcfe:
                               
Production costs
  $ 1.54     $ 2.03     $ (0.49 )     (24.1 )%
Transportation expense (intercompany)
  $ 1.89     $ 1.63     $ 0.26       16.0 %
Depreciation, depletion and amortization
  $ 1.48     $ 2.47     $ (0.99 )     (40.1 )%
 
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. This decrease was primarily the result of a decrease in average realized sales prices of $82.5 million coupled with a minimal decrease in volumes accounting for $0.1 million of the decrease. Our average realized prices, which exclude hedge settlements, on an equivalent basis (Mcfe) decreased to $3.68 per Mcfe for the year ended December 31, 2009 from $7.47 per Mcfe for the year ended December 31, 2008.
 
Oil and Gas Operating Expenses.  Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance and ad valorem taxes, and transportation expense. Oil and gas operating expenses decreased $5.1 million, or 6.4%, to $74.6 million during the year ended December 31, 2009, from $79.7 million during the year ended December 31, 2008.
 
Oil and gas production costs decreased $10.7 million, or 24.2%, to $33.4 million during the year ended December 31, 2009, from $44.1 million during the year ended December 31, 2008. This decrease was achieved through process improvement measures discussed above under “— Operating Highlights — Cost-cutting Measures.” Production costs, including gross production taxes and ad valorem taxes, were $1.54 per Mcfe for the year ended December 31, 2009 as compared to $2.03 per Mcfe for the year ended December 31, 2008.
 
Transportation expense increased $5.6 million, or 15.7%, to $41.1 million during the year ended December 31, 2009, from $35.5 million during the year ended December 31, 2008. The increase was primarily due to the increase in the contracted rate charged by our Cherokee Basin gathering pipeline in 2009 compared to 2008. The per unit cost increased $0.26 per Mcfe to $1.89 per Mcfe for the year ended December 31, 2009 as compared to $1.63 per Mcfe for the year ended December 31, 2008.
 
Depreciation, Depletion and Amortization.  We are subject to variances in our depletion rates from period to period due to changes in our oil and natural gas reserve quantities, production levels, product prices


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and changes in the depletable cost basis of our oil and natural gas properties. Our depreciation, depletion and amortization decreased approximately $21.5 million, or 40.1%, during the year ended December 31, 2009 to $32.2 million from $53.7 million during the year ended December 31, 2008. On a per unit basis, we had a decrease of $0.99 per Mcfe to $1.48 per Mcfe during the year ended December 31, 2009 from $2.47 per Mcfe during the year ended December 31, 2008. This decrease was primarily due to the impairments of our oil and gas 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.
 
Impairment of Oil and Natural Gas Properties.  We recorded an impairment of oil and natural gas properties of $102.9 million during the first quarter of 2009. See “— Operating Highlights — Material Events and Transactions — Oil and natural gas impairment” above. We recognized impairments of our oil and natural gas properties of $298.9 million for 2008.
 
Natural Gas Pipelines Segment
 
                                 
    Year Ended December 31,              
    2009     2008     Increase/(Decrease)  
    ($ in thousands, except per Mcf data)  
 
Natural Gas Pipeline Revenue:
                               
Gas pipeline revenue — Third Party
  $ 26,188     $ 28,176     $ (1,988 )     (7.1 )%
Gas pipeline revenue — Intercompany
  $ 41,135     $ 35,546     $ 5,589       15.7 %
                                 
Total natural gas pipeline revenue
  $ 67,323     $ 63,722     $ 3,601       5.7 %
Pipeline operating expense
  $ 29,083     $ 29,742     $ (659 )     (2.2 )%
Depreciation and amortization expense
  $ 15,609     $ 16,735     $ (1,126 )     (6.7 )%
Impairment of long-lived assets
  $ 165,728     $     $ 165,728       *%
Throughput Data (Mcf):
                               
Throughput — Third Party
    11,095       11,111       (16 )     (0.1 )%
Throughput — Intercompany
    24,510       25,390       (880 )     (3.5 )%
                                 
Total throughput (Mcf)
    35,605       36,501       (896 )     (2.5 )%
Average Pipeline Operating Costs per Mcf:
                               
Pipeline operating expense
  $ 0.82     $ 0.81     $ 0.01       1.2 %
Depreciation and amortization
  $ 0.44     $ 0.46     $ (0.02 )     (4.3 )%
 
 
* Not meaningful
 
Pipeline Revenue.  Total natural gas pipeline revenue increased $3.6 million, or 5.7%, to $67.3 million during the year ended December 31, 2009, from $63.7 million during the year ended December 31, 2008.
 
Third party natural gas pipeline revenue decreased $2.0 million, or 7.1%, to $26.2 million during the year ended December 31, 2009, from $28.2 million during the year ended December 31, 2008. The decrease was primarily due to the loss of a significant customer, MGE, as well as a renewal of certain contracts with another customer, KGS, at lower volumes and rates.
 
Intercompany natural gas pipeline revenue increased $5.6 million, or 15.7%, to $41.1 million during the year ended December 31, 2009, from $35.5 million during the year ended December 31, 2008. The increase was primarily due to the increase in the contracted rate charged by our Cherokee Basin gathering pipeline in 2009 compared to 2008.
 
Pipeline Operating Expense.  Pipeline operating expense was generally flat, decreasing $0.6 million, or 2.2%, to $29.1 million during the year ended December 31, 2009 from $29.7 million during the year ended December 31, 2008. Pipeline operating costs per unit increased $0.01 per Mcf, from $0.81 per Mcf for the year ended December 31, 2008 to $0.82 per Mcf for the year ended December 31, 2009.


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Depreciation and Amortization.  Depreciation and amortization expense decreased $1.1 million, or 6.7%, to $15.6 million during the year ended December 31, 2009, from $16.7 million during the year ended December 31, 2008.
 
Impairment of Long-lived Assets.  During the fourth quarter of 2009, we recorded an impairment of $165.7 million on our pipeline assets and related intangibles. See “— Operating Highlights — Material Events and Transactions — Pipeline segment impairment” above. No such impairment was required in 2008.
 
Unallocated Items
 
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 the $26 million of cash received as a result of amending or exiting certain of our above-market derivative financial instruments in June 2009.
 
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. See “— Liquidity and Capital Resources — Sources of Liquidity in 2009 and Capital Requirements — Credit Agreements” below.
 
Recovery from Misappropriation of Funds.  We recorded a recovery of misappropriated funds of $3.4 million for 2009. See “— Operating Highlights — Material Events and Transactions — Settlement of misappropriation” above.
 
Year ended December 31, 2008 compared to the year ended December 31, 2007
 
Oil and Gas Production Segment
 
                                 
    Year Ended
       
    December 31,   Increase/
    2008   2007   (Decrease)
    ($ in thousands)
 
Oil and gas sales
  $ 162,499     $ 105,285     $ 57,214       54.3 %
Oil and gas production costs
  $ 44,111     $ 36,295     $ 7,816       21.5 %
Transportation expense (intercompany)
  $ 35,546     $ 29,179     $ 6,367       21.8 %
Depreciation, depletion and amortization
  $ 53,710     $ 33,812     $ 19,898       58.8 %
Impairment of oil and gas properties
  $ 298,861     $     $ 298,861       * %
 
 
* Not meaningful


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Production.  The following table presents the primary components of revenues of our Oil and Gas Production Segment (oil and natural gas production and average oil and natural gas prices), as well as the average costs per Mcfe, for the fiscal years ended December 31, 2008 and 2007.
 
                                 
    Year Ended
       
    December 31,   Increase/
    2008   2007   (Decrease)
 
Production Data:
                               
Total production (Mmcfe)
    21,748       17,017       4,731       27.8 %
Average daily production (Mmcfe/d)
    59.4       46.6       12.8       27.5 %
Average Sales Price per Unit (Mcfe)
  $ 7.47     $ 6.19     $ 1.28       20.7 %
Average Unit Costs per Mcfe:
                               
Production costs
  $ 2.03     $ 2.13     $ (0.10 )     (4.7 )%
Transportation expense (intercompany)
  $ 1.63     $ 1.71     $ (0.08 )     (4.7 )%
Depreciation, depletion and amortization
  $ 2.47     $ 1.99     $ 0.48       24.1 %
 
Oil and Gas Sales.  Oil and gas sales increased $57.2 million, or 54.3%, to $162.5 million during the year ended December 31, 2008. This increase was the result of increased sales volumes and an increase in average realized prices. Additional volumes of 4,731 Mmcfe accounted for $32.2 million of the increase. The increased volumes resulted from additional wells completed in 2008. The remaining increase of $25.0 million was attributable to an increase in the average product price in 2008. Our average product prices, which exclude hedge settlements, on an equivalent basis (Mcfe) increased to $7.47 per Mcfe for the 2008 period from $6.19 per Mcfe for the 2007 period.
 
Oil and Gas Operating Expenses.  Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $14.2 million, or 21.7%, to $79.7 million during the year ended December 31, 2008, from $65.5 million during the year ended December 31, 2007.
 
Oil and gas production costs increased $7.8 million, or 21.5%, to $44.1 million during the year ended December 31, 2008, from $36.3 million during the year ended December 31, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $2.03 per Mcfe for the year ended December 31, 2008 as compared to $2.13 per Mcfe for the year ended December 31, 2007. The decrease in per unit cost was due to higher volumes over which to spread fixed costs.
 
Transportation expense increased $6.4 million, or 21.8%, to $35.5 million during the year ended December 31, 2008, from $29.2 million during the year ended December 31, 2007. The increase was primarily due to increased volumes, which resulted in additional expense of approximately $7.6 million. This increase was offset by a decrease in per unit cost of $0.08 per Mcfe. Transportation expense was $1.63 per Mcfe for the year ended December 31, 2008 as compared to $1.71 per Mcfe for the year ended December 31, 2007. This decrease in per unit cost was due to increased volumes, over which to spread fixed costs.
 
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 increased approximately $19.9 million, or 58.8%, in 2008 to $53.7 million from $33.8 million in 2007. On a per unit basis, we had an increase of $0.48 per Mcfe to $2.47 per Mcfe in 2008 from $1.99 per Mcfe in 2007. This increase was primarily due to downward revisions in our proved reserves, resulting in an increase in the per unit rate. In addition, depreciation and amortization increased approximately $5.5 million primarily due to additional vehicles, equipment and facilities acquired in 2008.
 
Impairment of Oil and Gas Properties.  We recognized impairments of our oil and gas properties of $298.9 million for the year ended December 31, 2008. Under full cost method accounting, we are required to compute the after-tax present value of our proved oil and gas properties using spot market prices for oil and gas at our balance sheet date. The base for our spot prices for gas is Henry Hub. On December 31, 2008, the


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spot price for gas at Henry Hub was $5.71 per Mmbtu and the spot oil price was $44.60 per Bbl compared to $6.43 per Mmbtu and $92.01 per barrel, at December 31, 2007.
 
Natural Gas Pipelines Segment
 
                                 
    Year Ended
             
    December 31,              
    2008     2007     Increase/(Decrease)  
          ($ in thousands)        
 
Natural Gas Pipeline Revenue:
                               
Gas pipeline revenue — Third Party
  $ 28,176     $ 9,853     $ 18,323       186.0 %
Gas pipeline revenue — Intercompany
  $ 35,546     $ 29,179     $ 6,367       21.8 %
                                 
Total natural gas pipeline revenue
  $ 63,722     $ 39,032     $ 24,690       63.3 %
Pipeline operating expense
  $ 29,742     $ 21,098     $ 8,644       41.0 %
Depreciation and amortization expense
  $ 16,735     $ 5,970     $ 10,765       180.3 %
Throughput Data (Mcf):
                               
Throughput — Third Party
    11,111       1,686       9,425       559.0 %
Throughput — Intercompany
    25,390       17,148       8,242       48.1 %
                                 
Total throughput (Mcf)
    36,501       18,834       17,667       93.8 %
Average Pipeline Operating Costs per Mcf:
                               
Pipeline operating expense
  $ 0.81     $ 1.12     $ (0.31 )     (27.7 )%
Depreciation and amortization
  $ 0.46     $ 0.32     $ 0.14       43.8 %
 
Pipeline Revenue.  Total natural gas pipeline revenue increased $24.6 million, or 63.3%, to $63.7 million during the year ended December 31, 2008, from $39.0 million during the year ended December 31, 2007.
 
Third-party natural gas pipeline revenue increased $18.3 million, or 186.0%, to $28.2 million during the year ended December 31, 2008, from $9.9 million during the year ended December 31, 2007. The increase was primarily related to the KPC Pipeline, which was acquired November 1, 2007. During the year ended December 31, 2008, the KPC Pipeline had revenues of $19.5 million compared to $3.2 million for the period from November 1, 2007 through December 31, 2007. The remaining increase of $2.0 million was due to additional third-party volumes on our gathering system.
 
Intercompany natural gas pipeline revenue increased $6.4 million, or 21.8%, to $35.5 million during the year ended December 31, 2008, from $29.2 million during the year ended December 31, 2007. The increase is due to the 48.1% increase in throughput volumes from our Cherokee Basin properties and the higher gathering and compression fees resulting from the midstream services agreement that became effective January 1, 2008.
 
Pipeline Operating Expense.  Pipeline operating expense increased $8.6 million, or 41.0%, to $29.7 million during the year ended December 31, 2008, from $21.1 million during the year ended December 31, 2007. This increase is primarily the result of our acquisition of the KPC Pipeline in November 2007. Therefore, 2007 only had two months of expenses versus 12 months in 2008. During the year ended December 31, 2008, the KPC Pipeline had operating costs of $7.7 million compared to operating costs of $1.1 million during the period from November 1, 2007 through December 31, 2007. The remaining increase of $2.0 million is due to increased throughput volumes in 2008. Pipeline operating costs per unit decreased $0.31 per Mcf during 2008, from $1.12 per Mcf to $0.81 per Mcf. The decrease in per unit cost was the result of higher volumes, over which to spread fixed costs, as well as our cost-cutting efforts implemented in the third quarter of 2008.
 
Depreciation and Amortization.  Depreciation and amortization expense increased $10.8 million, or 180.3%, to $16.7 million during the year ended December 31, 2008, from $6.0 million during the year ended December 31, 2007. The increase is primarily due to the amortization of our intangibles of $4.3 million acquired in the KPC Pipeline acquisition, as well as an increase in depreciation on our pipelines of $1.7 million. During the year ended December 31, 2008, the KPC Pipeline had depreciation and amortization expense of $5.6 million compared to $0.8 million for the period from November 1, 2007 through December 31,


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2007. The remaining increase is due to the additional natural gas gathering pipeline installed during the year ended December 31, 2008.
 
Unallocated Items
 
General and Administrative Expenses.  General and administrative expenses increased $7.2 million, or 34.5%, to $28.3 million during the year ended December 31, 2008, from $21.0 million during the year ended December 31, 2007. The increase is primarily due to the internal investigation and restatements and reaudits ($4.7 million), increased rent in connection with establishing a Houston office and new corporate headquarters ($1.7 million), the inclusion of the KPC Pipeline for all of 2008 compared to two months in 2007 ($2.5 million), and headcount (7%) and salary (10%) increases to support the growth of our company ($0.8 million). These amounts were partially offset by lower stock compensation expense ($3.9 million) in connection with the departure of QRCP’s and QELP’s former chief executive and financial officers. The remaining increase was the result of the costs associated with QELP being a separate publicly traded company.
 
Loss from Misappropriation of Funds.  In connection with the unauthorized transfers of funds by certain former executives of QRCP and QELP, we recorded a loss from misappropriation of funds of $2.0 million for the year ended December 31, 2007.
 
Other Income (Expense).  Gain from derivative financial instruments increased $64.1 million to $66.1 million during the year ended December 31, 2008, from $2.0 million during the year ended December 31, 2007. Due to the decline in average natural gas and crude oil prices during the second half of 2008, we recorded a $72.5 million unrealized gain and $6.4 million realized loss on our derivative contracts for the year ended December 31, 2008 compared to a $5.3 million unrealized loss and $7.3 million realized gain for the year ended December 31, 2007. Unrealized gains are attributable to changes in natural gas prices and volumes hedged from one period end to another.
 
Interest Expense, net.  Interest expense, net decreased $18.3 million, or 41.8%, to $25.4 million during the year ended December 31, 2008, from $43.6 million during the year ended December 31, 2007. The decreased interest expense for the year ended December 31, 2008 relates to the write-off of $9.9 million of deferred debt issuance costs recorded in connection with the refinancing of our credit facilities during 2007 and lower interest rates during 2008.
 
Liquidity and Capital Resources
 
Our significant financial highlights as of December 31, 2009 include:
 
  •  Reduced total debt by $58.8 million from December 31, 2008.
 
  •  Increased cash and cash equivalents by $7.1 million from December 31, 2008.
 
  •  Repriced derivatives during the second quarter of 2009 and received $26 million.
 
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 of oil and natural gas and the prices received from the sale of this production and revenue generated from our pipeline operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.
 
Cash flows from operations totaled $74.6 million for the year ended December 31, 2009, as compared to $61.9 million and $28.8 million for the years ended December 31, 2008 and 2007, respectively. The increase from 2008 to 2009 is attributable primarily to an increase in realized gains on our derivatives offset by lower revenues due to depressed oil and natural gas prices in 2009. The increase from 2007 to 2008 is attributable primarily to net cash from increased production and from higher average oil and natural gas prices in 2008


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(although 2008 prices began to decline significantly in the third quarter of 2008) compared with average prices during 2007.
 
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, pipeline expansion and acquisitions of businesses. Net cash from investing activities totaled $0.3 million for the year ended December 31, 2009, as compared to cash used of $266.6 million and $272.5 million for the years ended December 31, 2008 and 2007, respectively. 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. Our liquidity constraints during 2009 were largely the result of required debt payments triggered by decreases in the borrowing base of QELP’s credit facility, decreased revenues due to lower oil and natural gas market prices and increased general and administrative costs resulting from our internal investigation of the misappropriation, reaudits and restatements of previously issued financial statements and recombination activities. The following table sets forth our capital expenditures by major categories in 2009, 2008 and 2007.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Capital expenditures:
                       
Leasehold acquisition
  $ 1,998     $ 18,945     $ 15,847  
Exploration
    128       1,273        
Development
    5,087       58,070       67,586  
Acquisition of PetroEdge
          142,618        
Acquisition of Seminole County, Oklahoma property
          9,500        
Acquisition of KPC Pipeline
                124,936  
Pipelines
    1,835       27,649       48,668  
Other items (primarily capitalized overhead and interest)
    511       9,061       7,832  
                         
Total capital expenditures
  $ 9,559     $ 267,116     $ 264,869  
                         
 
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 $67.8 million for the year ended December 31, 2009, as compared to cash provided of $211.8 million and $216.5 million for the years ended December 31, 2008 and 2007, respectively. 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, and $24.4 million of distributions to unitholders.
 
Working Capital Deficit.  At December 31, 2009, we had current assets of $66.0 million. Our working capital (current assets minus current liabilities) was a deficit of $282.7 million at December 31, 2009 (excluding the short-term derivative asset and liability of $10.6 million and $1.4 million, respectively), compared to a working capital deficit of $41.5 million at December 31, 2008 (excluding the short-term derivative asset and liability of $43.0 million and $12,000 respectively). The decrease in our working capital was due to $310.0 million of our credit facilities being due in 2010. Of this amount, $282.5 million was due on July 11, 2010 because the recombination had not closed as of December 31, 2009. Subsequent to December 31, 2009, the recombination closed. Accordingly, the maturity date of the $282.5 million has been extended to March 31, 2011.


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Credit Agreements
 
QRCP
 
QRCP entered into a second amended and restated credit agreement with Royal Bank of Canada (“RBC”) on September 11, 2009. At the time of the amendment, QRCP’s credit agreement included a term loan with principal balance of $28.3 million, an $8.0 million revolving line of credit and three promissory notes. The promissory notes included an $862,786 interest deferral note dated June 30, 2009 (representing outstanding due and unpaid interest on the term loan), a $282,500 payment-in-kind note dated May 29, 2009 (representing a 1% amendment fee payable by QRCP in connection with the fourth amendment to QRCP’s credit facility), and a second $25,000 payment-in-kind note dated June 30, 2009 (representing an amendment fee payable by QRCP in connection with the fifth amendment to the credit facility). Interest on the term loan and promissory notes can be deferred at our election whereupon the deferred interest would be added to existing principal balances. On December 17, 2009, QRCP entered into a further amendment that provides for QRCP to guarantee the credit facilities of QELP and QMLP after the recombination and to pledge its ownership interests in QELP and QMLP to secure its guarantees. As of December 31, 2009, the balance, including deferred interest, of the term loan was $30.1 million and of the promissory notes was $1.3 million, while the balance on the revolving line of credit was $4.3 million.
 
Modification of Debt.  As a result of the amendment and restatement to the credit agreement on September 11, 2009, QRCP evaluated the remaining cash flows of this facility under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 470-50-40 Debt — Modifications and Extinguishments — Derecognition to determine if the facility had been substantially modified as defined by the guidance. Upon determining that a substantial modification had occurred, QRCP recorded an extinguishment of prior debt and the assumption of new debt at fair value. Our analysis indicated that the fair value of the new debt facility was not materially different from the principal amount of the previous debt facility. As a result, QRCP recorded a $0.8 million loss on extinguishment of debt which represents a write-off of unamortized debt issuance costs associated with the prior debt facility. The loss is reflected in interest expense in our consolidated statements of operations.
 
Interest Rate and Other Fees.  Interest accrues on the QRCP term loan, the interest deferral note and the two payment-in-kind notes at the base rate plus 10.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.50% or RBC’s prime rate for such day. The revolving line of credit is non-interest bearing. QRCP is required to pay to the lenders a facility fee equal to $2.0 million on the earlier of July 11, 2010 and the date the facility fee reduction conditions described in the next sentence are satisfied. The facility fee will be proportionately reduced if all of the following facility fee reduction conditions are satisfied: (i) repayment and termination by QRCP of the revolving line of credit, (ii) payment of the deferred quarterly principal payments under the term loan as discussed below under “— Payments,” (iii) repayment of the interest deferral note and the two payment-in-kind notes and (iv) payment of any deferred interest under the term loan, the interest deferral note and the two payment-in-kind notes as discussed below under “— Payments.”
 
Additionally, two of QRCP’s subsidiaries assigned to the lenders an overriding royalty interest in the oil and gas properties owned by them in the aggregate equal to 2% of its respective working interest (plus royalty interest, if any), proportionately reduced, in its respective oil and gas properties. Each lender agreed to reconvey the overriding royalty interest (and any accrued payments owing to such lender) if on or before July 11, 2010 the facility fee reduction conditions discussed above are satisfied and the term loan (together with accrued and unpaid interest) is paid in full. Each lender also agreed to reconvey the overriding royalty interest (but not any accrued payments owing to such lender) if on or before July 11, 2010 the facility fee reduction conditions discussed above are satisfied.
 
Payments.  Quarterly principal payments of $1.5 million on the term loan due September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010 have been effectively deferred until July 11, 2010, at which time all $6 million will be due in order to satisfy the facility fee reduction conditions discussed above under “— Interest Rate and Other Fees.” Commencing with the calendar quarter ended September 30, 2010,


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QRCP is required to make a principal repayment of $1.5 million at the end of each calendar quarter until maturity.
 
Maturity Dates.  The maturity date of the term loan is January 11, 2012. The maturity date of the revolving line of credit, the interest deferral note and the two payment-in-kind notes is July 11, 2010. The revolving line of credit, term loan, interest deferral note and the two payment-in-kind notes may be prepaid at any time without any premium or penalty. On July 11, 2010, the total amount due by QRCP under its credit agreement (assuming the facility fee reduction conditions are all satisfied on that date) will be approximately $21 million.
 
Security Interest.  The QRCP credit agreement is secured by a first priority lien on the oil and gas properties owned by Quest Eastern in the Appalachian Basin, which are substantially all of QRCP’s assets. The assets of QMLP, QELP and their subsidiaries are not pledged to secure the QRCP term loan. The QRCP credit agreement provides that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates (or BP Corporation North America, Inc. or its affiliates), are secured pari passu by the liens granted under the loan documents. In connection with the recombination, the security interest in QRCP’s ownership interest in QELP and QMLP was released in order to permit QRCP to pledge such ownership interests to secure its guarantee of the credit facilities of QELP and QMLP, respectively.
 
Covenants.  The QRCP credit agreement contains non-financial affirmative and negative covenants that are customary for credit agreements of this type. The financial covenants have been removed from the QRCP credit agreement, but QRCP and RBC agreed that if the facility fee reduction conditions discussed above under “— Interest Rate and Other Fees” are satisfied on or before July 11, 2010, they would negotiate in good faith to amend the credit agreement to add financial covenants customary for similar credit agreements of this type.
 
Events of Default.  Events of default are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control. In addition, it was an event of default under QRCP’s credit agreement if by January 15, 2010, QRCP had not (i) delivered to RBC evidence that the recombination has been agreed to by the lenders under QELP’s and QMLP’s credit agreements and (ii) delivered to RBC evidence that the board of directors of each of QRCP, QELP, QMLP and certain of their subsidiaries have approved the terms of any amendments, restatements or new credit facilities to renew, rearrange or replace the existing credit agreements of each of QELP and QMLP. This requirement was satisfied with the execution of the amendments to QELP’s and QMLP’s credit agreements on December 17, 2009.
 
QELP
 
Quest Cherokee Credit Agreement.  QELP is a party, as a guarantor, to an amended and restated credit agreement with its wholly-owned subsidiary, Quest Cherokee, LLC (“Quest Cherokee”), as the borrower, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. QELP entered into a fifth amendment to the Quest Cherokee credit agreement on December 17, 2009. QELP agreed to pay an amendment fee of 0.50% of the outstanding principal amount of the Quest Cherokee credit agreement, which fee is payable on the maturity date of the loan. The outstanding balance under the credit agreement was $145 million as of December 31, 2009, with no available capacity.
 
Modification of Debt.  As a result of the amendment to the credit agreement on December 17, 2009, QELP evaluated the change in borrowing capacity of this facility under FASB ASC 470-50-40 Debt — Modifications and Extinguishments — Derecognition. Upon determining that a reduction in borrowing capacity had occurred, QELP wrote off a pro-rata portion of prior unamortized debt issuance costs in the amount of $0.8 million while capitalizing $3.4 million of direct costs associated with the current amendment. Included in this amount was $0.7 million that QELP, under the terms of the amendment, elected to defer payment until


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maturity of the credit agreement. The write-off is reflected in interest expense in the consolidated statements of operations.
 
Borrowing Base.  The Quest Cherokee credit agreement consists of a three-year $145 million credit facility. In connection with the December 17, 2009 amendment, the revolving credit facility was converted to a term loan and no future borrowings are permitted under the credit facility. The maximum outstanding amount under the credit facility is tied to a borrowing base that will be redetermined by the lenders every three months taking into account the value of QELP’s proved reserves. In addition, QELP and the required lenders each have the right to initiate a redetermination of the borrowing base between each scheduled redetermination, provided that no more than two such redeterminations may occur in a 12 month period, and in certain other limited circumstances. If the borrowing base is reduced in connection with a redetermination, outstanding borrowings in excess of the new borrowing base will be required to be repaid (1) either within 30 days following receipt of notice of the new borrowing base or in two equal monthly installments beginning on or before the 30th day following receipt of notice of the new borrowing base or (2) immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 2% of the borrowing base. As of June 30, 2009, the borrowing base was $160 million (reduced from $190 million at December 31, 2008). At that time, there was a borrowing base deficiency which has been resolved but which left no remaining borrowing capacity. Effective December 17, 2009, QELP’s borrowing base under its revolving credit agreement was further reduced to $145 million in connection with another borrowing base redetermination, which resulted in a borrowing base deficiency of $15 million. QELP repaid the borrowing base deficiency on December 17, 2009 in connection with the execution of the amendment to the Quest Cherokee credit agreement.
 
Payments.  The outstanding principal amount of the Quest Cherokee credit agreement must be reduced to the amounts and by the dates specified below (in thousands):
 
         
March 31, 2010
  $ 141,000  
June 30, 2010
  $ 141,000  
September 30, 2010
  $ 138,000  
December 31, 2010
  $ 134,000  
 
The remaining balance of the Quest Cherokee credit agreement is due on the maturity date.
 
In addition, Quest Cherokee must make a prepayment within 20 business days after the end of each calendar quarter (beginning with the quarter ending March 31, 2010) in an amount equal to QELP’s Excess Book Cash. Excess Book Cash is equal to book cash at the end of a quarter less the sum of the following: (i) restricted cash set aside for accrued royalty payments, (ii) restricted cash set aside to secure letters of credit, (iii) restricted cash set aside for accrued and unpaid taxes, (iv) quarterly estimated federal income taxes, to the extent not already reflected in (iii) above, (v) restricted cash set aside for any other amounts accrued and unpaid during the quarter and approved by the required lenders under the credit agreement, and (vi) $5 million.
 
Interest Rate.  Interest generally accrues at either LIBOR plus 4.0% or the base rate plus 3.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%.
 
Maturity Date.  As of December 31, 2009, the maturity date of the Quest Cherokee credit agreement was July 11, 2010 since the recombination had not closed on that date. Subsequent to December 31, 2009, the recombination closed. Accordingly, the maturity date is March 31, 2011.
 
Security Interest.  The Quest Cherokee credit agreement is secured by a first priority lien on substantially all of the assets of QELP and its subsidiaries. All obligations arising under the loan documents, including obligations under any hedging agreement entered into with the lenders and their affiliates (or BP Corporation North America, Inc. or its affiliates), are secured pari passu by the liens granted under the loan documents. The Quest Cherokee credit agreement is also secured by the guarantee of PostRock and QRCP and a pledge of all of QRCP’s equity interest in QELP.


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Covenants.  The agreement contains affirmative and negative covenants that are customary for transactions of this type, including financial covenants that prohibit QELP, Quest Cherokee and any of their subsidiaries from:
 
  •  permitting the ratio of QELP’s consolidated current assets (as defined) to consolidated current liabilities (as defined) at any fiscal quarter-end to be less than 1.0 to 1.0;
 
  •  permitting the interest coverage ratio of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and
 
  •  permitting the leverage ratio of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.
 
Events of Default.  Events of default are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, borrowing base deficiencies, and change of control.
 
The fifth amendment to the Quest Cherokee credit agreement excluded any actions to effect the recombination and the recombination itself from the definition of a change of control. The fifth amendment also added the concept of a change of control of PostRock as an event of default.
 
Second Lien Loan Agreement.  QELP and Quest Cherokee are parties to a $45 million second lien loan agreement. QELP entered into an eighth amendment to the second lien loan agreement on December 17, 2009. QELP agreed to pay an amendment fee of 2.10% of the outstanding principal amount of the second lien loan agreement, which fee is payable on the maturity date of the loan. The fee will be partially forgiven if the second lien term loan is repaid in full on or before February 28, 2011. The outstanding balance under the loan was $29.8 million as of December 31, 2009.
 
Modification of Debt.  As a result of the eighth amendment to the second lien loan on December 17, 2009, QELP evaluated the remaining cash flows of this facility under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 470-50-40 Debt — Modifications and Extinguishments — Derecognition and determined that facility had not been substantially modified. An additional $0.9 million of direct costs associated with the amendment was capitalized. Included in this amount was $0.6 million that QELP, under the terms of the amendment, elected to defer payment until maturity of the loan.
 
Interest Rate.  Interest accrues under the second lien loan agreement at either LIBOR plus 11.0% (with a LIBOR floor of 3.5%) or the base rate plus 10.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.5%, RBC’s prime rate or LIBOR plus 1.25%. Amounts due under the second lien loan agreement may be prepaid without any premium or penalty, at any time. QELP may elect to defer the payment of a portion of the interest (at the rate of up to 2%) until maturity. If any amount is outstanding under the Quest Cherokee credit agreement, such interest amount must be deferred. Deferred interest will bear interest.
 
Payments.  No prepayments may be made on the second lien term loan while the Quest Cherokee credit agreement is outstanding. After the Quest Cherokee credit agreement is paid in full, Quest Cherokee must make a prepayment within 20 business days after the end of each calendar quarter (beginning with the quarter ending March 31, 2010) in an amount equal to QELP’s Excess Book Cash.
 
Maturity Date.  As of December 31, 2009, the maturity date of the second lien loan agreement was July 11, 2010 since the recombination had not closed on that date. Subsequent to December 31, 2009, the recombination closed. Accordingly, the maturity date is March 31, 2011.
 
Security Interest.  The second lien loan agreement is secured by a second priority lien on substantially all of the assets of QELP and its subsidiaries. The second lien loan agreement is also secured by the guarantee


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of PostRock and QRCP (which is subordinated to the guarantees of the Quest Cherokee credit agreement and the QMLP credit agreement) and a second lien pledge of all of QRCP’s equity interest in QELP.
 
Covenants.  The second lien loan agreement contains affirmative and negative covenants that are customary for credit agreements of these types, including financial covenants that prohibit QELP, Quest Cherokee and any of their subsidiaries from:
 
  •  permitting the ratio of QELP’s consolidated current assets (as defined) to consolidated current liabilities (as defined) at any fiscal quarter-end to be less than 1.0 to 1.0;
 
  •  permitting the interest coverage ratio of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and
 
  •  permitting the leverage ratio of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.
 
The second lien loan agreement contains an additional financial covenant that prohibits QELP, Quest Cherokee, and any of their subsidiaries from permitting the total reserve leverage ratio (ratio of total proved reserves to consolidated funded debt) at any fiscal quarter-end to be less than 1.5 to 1.0.
 
Events of Default.  Events of default under the second lien loan agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness and change of control.
 
The eighth amendment to the Quest Cherokee credit agreement excluded any actions to effect the recombination and the recombination itself from the definition of a change of control. The eighth amendment also added the concept of a change of control of PostRock as an event of default.
 
QMLP
 
QMLP and Bluestem Pipeline, LLC, as borrowers, entered into a third amendment to the amended and restated QMLP credit agreement on December 17, 2009. The borrowers agreed to pay an amendment fee of 0.50% of the outstanding principal amount of the QMLP credit agreement, which fee is payable on the maturity date of the loan. In connection with the December 17, 2009 amendment, the QMLP credit agreement was converted to a term loan and no future borrowings are permitted under the QMLP credit agreement. As of December 31, 2009, the outstanding principal amount of the QMLP credit agreement was $118.7 million with $1.0 million of capacity available only for letters of credit.
 
Modification of Debt.  As a result of the amendment to the credit agreement on December 17, 2009, QMLP evaluated the change in borrowing capacity of this facility under FASB ASC 470-50-40 Debt — Modifications and Extinguishments — Derecognition. Upon determining that a reduction in borrowing capacity had occurred, QMLP wrote off a pro-rata portion of prior unamortized debt issuance costs in the amount of $1.9 million while capitalizing $2.1 million of direct costs associated with the amendment. Included in this amount was $0.6 million that QMLP, under the terms of the amendment, elected to defer payment until maturity of the credit agreement. The write-off is reflected in interest expense in the consolidated statements of operations.
 
Interest Rate.  Interest accrues at either LIBOR plus a margin ranging from 2.0% to 3.5% (depending on the total leverage ratio) or the base rate plus a margin ranging from 1.0% to 2.5% (depending on the total leverage ratio), at the borrowers’ option. The base rate is generally the higher of the federal funds rate plus 0.5%, RBC’s prime rate or LIBOR plus 1.25%.
 
Payments.  There are no scheduled principal payments prior to the maturity date.


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Maturity Dates.  As of December 31, 2009, the maturity date of the QMLP credit agreement was July 11, 2010 since the recombination had not been closed on that date. Subsequent to December 31, 2009, the recombination closed. Accordingly, the maturity date is March 31, 2011.
 
Security Interest.  The QMLP credit agreement is secured by a first priority lien on substantially all of the assets of QMLP and its subsidiaries. The QMLP credit agreement is also secured by the guarantee of PostRock and QRCP and a pledge of all of QRCP’s equity interest in QMLP.
 
Covenants.  The QMLP credit agreement contains affirmative and negative covenants that are customary for credit agreements of this type.
 
The QMLP credit agreement contains financial covenants that prohibit QMLP and any of its subsidiaries from:
 
  •  permitting the interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) on a rolling four quarter basis to be less than 2.50 to 1.00 for the fiscal quarter ending on or prior to March 31, 2010 and increasing to 2.75 to 1.00 for each fiscal quarter end thereafter; and
 
  •  permitting the total leverage ratio (ratio of adjusted consolidated funded debt to adjusted consolidated EBITDA) on a rolling four quarter basis to be greater than 5.00 to 1.00 for the fiscal quarter ending on or prior to March 31, 2010, and decreasing to 4.50 to 1.00 for each fiscal quarter end thereafter.
 
Events of Default.  Events of default under the QMLP credit agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control.
 
The third amendment to the QMLP Credit Agreement excluded any actions to effect the recombination and the recombination itself from the definition of a change of control. The third amendment also added the concept of a change of control of PostRock as an event of default.
 
As a result of the recent expiration of MGE’s firm transportation contract with the KPC Pipeline and the expected decrease in 2010 in the gathering and compression fees charged under the midstream services agreement between QELP and a subsidiary of QMLP as a result of the low natural gas prices in 2009, QMLP may not be in compliance with the total leverage ratio covenant commencing with the second quarter of 2010, if it is not able to reduce its expected total indebtedness as of June 30, 2010 and/or increase its anticipated EBITDA for the quarter ended June 30, 2010. If QMLP were to default, the lenders could accelerate the entire amount due under the QMLP credit agreement.
 
Sources of Liquidity in 2010 and Capital Requirements
 
During 2009, due to lower gas prices and the amount of the gathering rate QELP was obligated to pay to QMLP relative to the price at which it could sell its gas, it was not economical for QELP to drill new wells, complete existing wells or produce gas from new wells. Furthermore, QRCP did not have the capital necessary to drill any wells. Therefore, the only wells drilled and completed in 2009 were the seven necessary to hold otherwise expiring acreage. If we can successfully refinance our debt, we will be able to operate as one entity and the gathering costs are an expense of production without a built-in profit, allowing us to be in a better position to drill, complete and profitably produce gas, even in a low gas price environment. In addition, management believes that the recombination has put us in a better position to add reserves and production, depending on capital availability. Management also expects the recombined production and gathering operations and the simplified structure of the organization to be more attractive to potential capital providers.
 
In 2010, we intend to focus on maintaining a stable asset base, improving the profitability of our assets by increasing our utilization while controlling costs and raising equity capital. For 2010, we have budgeted approximately $6.0 million to complete and $5.5 million to connect 108 gross wells that were previously drilled but not completed, $2.7 million for land and equipment in the Cherokee Basin, $20 million of net


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expenditures to drill and complete three vertical wells and six horizontal wells and $2.5 million for land, equipment and connections in the Appalachian Basin. These wells will be drilled on locations that are classified as containing proved reserves in the December 31, 2009 reserve report. We intend to fund these capital expenditures only to the extent that we have available cash from operations after taking into account our debt service and other obligations, and with the proceeds from additional equity capital issuances and borrowings.
 
In order to accomplish the goals and objectives set forth above, no later than the first half of 2010, we will need to either refinance our debt to allow for available capital or raise a sufficient amount of equity capital to fund our drilling program and pay down outstanding indebtedness. We may not be able to raise a sufficient amount of equity capital for these purposes at the appropriate time which would restrict our ability to fund our operations and capital expenditures and we may be forced to file for bankruptcy. We are actively seeking to refinance our current credit facilities, although we may not be able to do so on favorable terms or at all.
 
As discussed above, quarterly principal payments of $1.5 million on QRCP’s term loan due September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010 are deferred until July 11, 2010, at which time all $6 million will be due. In addition, the maturity date of the revolving line of credit, interest deferral notes and the two payment-in-kind notes will be July 11, 2010. On July 11, 2010, the total amount due by QRCP under its credit agreement (assuming the facility fee reduction conditions are all satisfied on that date) would be approximately $21 million. Payments of principal under the Quest Cherokee credit agreement in the amounts of $4.0 million, $0, $3.0 million and $4.0 million are due on the last day of each quarter of 2010. In addition, QELP may be required to make additional prepayments at the end of each calendar quarter beginning with the quarter ending March 31, 2010. There is no assurance that we will have sufficient funds to pay these amounts when they come due.
 
Contractual Obligations
 
We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at December 31, 2009 after giving effect to the extension of the maturity date of various facilities that occurred upon closing of the recombination:
 
                                         
    Payments Due by Period  
          Less Than
    1-3
    4-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
    (In thousands)  
 
Revolving Credit Facility — QRCP
  $ 4,300     $ 4,300     $     $     $  
Term Loan and Promissory Notes— QRCP
    31,358       12,108       19,250              
1st Lien Term Loan — QELP
    145,000       11,000       134,000              
2nd Lien Loan — QELP
    29,821             29,821              
Term Loan — QMLP
    118,728             118,728              
Other Note obligations
    103       58       34       11        
Interest expense on bank credit facilities
    26,055       20,461       5,594              
Operating lease obligations
    17,141       8,929       4,369       2,060       1,783  
                                         
Total commitments
  $ 372,506     $ 56,856     $ 311,796     $ 2,071     $ 1,783  
                                         
 
Off-Balance Sheet Arrangements
 
At December 31, 2009, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually


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narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.
 
Critical Accounting Policies
 
The preparation of our consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.
 
Oil and Gas Reserves
 
Our most significant financial estimates are based on estimates of proved oil and gas reserves. Proved reserves represent estimated quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserves estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are estimated on an annual basis by independent petroleum engineers.
 
In December 2008, the SEC adopted the final rules for the “Modernization of Oil and Gas Reporting.” The new rules require reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and permit the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies also are allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies are required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and potentially modify the classifications of proved and producing reserves. The calculation of reserves using an average price is a significant change that should reduce the volatility of our reserve calculation and could impact any potential future impairments arising from our ceiling test.
 
Oil and Gas Properties
 
The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for oil and natural gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our oil and gas properties are capitalized.
 
Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Holding all other factors constant, if proved oil and gas reserves were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties


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unless the sale or disposition represents a significant quantity of reserves, which would have a significant impact on the depreciation, depletion, and amortization rate.
 
Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of our full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that we will be required to write down the carrying value of our oil and gas properties increases when gas prices are depressed, even if low prices are temporary. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.
 
Through the quarter ended September 30, 2009, the ceiling test was calculated using natural gas prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. Beginning with the quarter ended December 31, 2009, a twelve-month average price is used and adjusted for basis differentials. In addition, subsequent to the adoption of FASB ASC 400-20 Retirement and Environmental Obligations-Asset Retirement Obligation, the future cash outflows associated with settling asset retirement obligations are not included in the computation of the discounted present value of future net revenues for the purpose of the ceiling test calculation.
 
Unevaluated Properties
 
The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base.
 
Future Abandonment Costs
 
We have significant legal obligations to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed, or developed. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. Upon initial recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are recorded as lease operating expense.
 
Estimating the future asset retirement liability requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these


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assumptions impact the present value of the existing asset retirement liability, a corresponding adjustment will be made to the carrying cost of the related asset.
 
We have not recorded any asset retirement obligations relating to our gathering systems as of December 31, 2009 and 2008 because we do not have any legal or constructive obligations relative to asset retirements of the gathering systems. We have recorded asset retirement obligations relating to the abandonment of our interstate pipeline assets (see discussion in Note 9 — Asset Retirement Obligations to the consolidated financial statements included in this Annual Report on Form 10-K).
 
Derivative Instruments
 
Due to the historical volatility of oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we use collars, fixed-price swaps and fixed price sales contracts as our mechanism for hedging commodity prices. Our current derivative instruments are not accounted for as hedges for accounting purposes in accordance with FASB ASC 815 Derivatives and Hedging (“FASB ASC 815”). As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized as gains and losses which are included in other income and expense in the period of change. While we believe that the stabilization of prices and production afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising natural gas prices. As a result of rising commodity prices, we may recognize additional charges to future periods; however, for the year ended December 31, 2009, we recognized a total gain on derivative financial instruments in the amount of $48.1 million, consisting of a $98.1 million realized gain and a $50.0 million unrealized loss. Our estimates of fair value are determined by the use of an option-pricing model that is based on various assumptions and factors including the time value of options, volatility, and closing NYMEX market indices.
 
Revenue Recognition
 
We derive revenue from our oil and natural gas operations from the sale of produced oil and natural gas. We use the sales method of accounting for the recognition of oil and gas revenue. Because there is a ready market for oil and natural gas, we sell our oil and natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title and risk of loss is transferred based on our net revenue interests. Oil and gas sold in production operations is not significantly different from our share of production based on our interest in the properties.
 
Settlement of oil and gas sales occur after the month in which the oil and gas was produced. We estimate and accrue for the value of these sales using information available at the time the financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser.
 
Revenue from our pipeline operations is recognized at the time the natural gas is gathered or transported through the system and delivered to a third party.
 
Income Taxes
 
We record our income taxes using an asset and liability approach in accordance with the provisions of FASB ASC 740 Income Taxes (“FASB ASC 740”). This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily intangible drilling costs and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under FASB ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
 
Estimating the amount of valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger limits on use of net


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operating losses under Internal Revenue Code section 382. We have a significant deferred tax asset associated with net operating loss carry-forward (NOLs).
 
Recent Accounting Pronouncements
 
In June 2009, the FASB issued FASB ASC 105 Generally Accepted Accounting Principles (“FASB ASC 105”), which establishes FASB ASC as the sole source of authoritative GAAP. Pursuant to the provisions of FASB ASC 105, we have updated references to GAAP in our financial statements for the year ended December 31, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.
 
In March 2008, the FASB issued provisions under FASB ASC 815 that did not change the accounting for derivatives but does require enhanced disclosures about derivative strategies and accounting practices. We adopted these provisions effective January 1, 2009.
 
We adopted the provisions of FASB ASC 260 Earnings Per Share (“FASB ASC 260”), effective January 1, 2009, with respect to whether instruments granted in share-based payment transactions are considered participating securities prior to vesting and therefore included in the allocation of earnings for purposes of calculating earnings per share (“EPS”) under the two-class method as required by FASB ASC 260. FASB ASC 260 provides that unvested unit-based awards that contain non-forfeitable rights to dividends are participating securities and should be included in the computation of EPS. Our restricted stock units contain non-forfeitable rights to dividends and thus require these awards to be included in the EPS computation. All prior periods have been conformed to the current year presentation. During periods of losses, EPS will not be impacted, as our participating securities are not obligated to share in our losses and thus, are not included in the EPS share computation.
 
In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. We implemented new rules at December 31, 2009. The impact of this change in prices was to increase depletion expense by approximately $1.0 million for the fourth quarter of 2009.
 
In May 2009, the FASB issued FASB ASC 855 Subsequent Events (“FASB ASC 855”). FASB ASC 855 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted FASB ASC 855 beginning with the period ended June 30, 2009.
 
In December 2007, the FASB issued FASB ASC 810 Consolidation (“FASB ASC 810”). FASB ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary. In addition, FASB ASC 810 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. FASB ASC 810-10 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. We adopted FASB ASC 810 effective January 1, 2009. Under FASB ASC 810, QRCP is required to classify amounts previously presented as a minority interest liability as a component of equity in the condensed consolidated balance sheet and is required to present net income (loss) attributable to QRCP and the noncontrolling partners’ ownership interest separately in the condensed consolidated statement of operations. All prior periods have been reclassified to comply with FASB ASC 810.


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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
 
Quantitative and Qualitative Disclosures about Market Risk
 
The discussion in this section provides information about the financial instruments we use to manage commodity price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the actual delivery of a commodity quantity to satisfy settlement.
 
Commodity Price Risk
 
Our most significant market risk relates to the prices we receive for our oil and natural gas production. For example, NYMEX-WTI oil prices ranged from a high of $81.37 per barrel in October 2009 to $33.98 per barrel in February 2009, with an average of approximately $62.09 per barrel in 2009. Meanwhile, near month NYMEX natural gas futures prices ranged from a high of $6.07 per Mmbtu in January 2009 to a low of $2.51 per Mmbtu in September 2009, with an average of approximately $4.16 per Mmbtu in 2009. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of oil and natural gas prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes to provide certainty on future sales prices and reduce revenue volatility.
 
We use, and may continue to use, a variety of commodity-based derivative financial instruments, including collars, fixed-price swaps and basis protection swaps. Our fixed price swap and collar transactions are settled based upon either NYMEX prices or index prices at our main delivery points, and our basis protection swap transactions are settled based upon the index price of natural gas at our main delivery points. Settlement for our natural gas derivative contracts typically occurs in advance of our purchaser receipts.
 
While we believe that the oil and natural gas price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas prices. We establish fair value of our derivative contracts by price quotations obtained from counterparties to the derivative contracts. Both realized and unrealized gains and losses from settlements of or changes in fair values of our derivative contracts are currently recognized in other income (expense) as they occur. As a result, our current period earnings may be significantly affected by changes in fair value of our commodities derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.
 
Gains and losses associated with derivative financial instruments related to gas and oil production were as follows for the years ended December 31, 2009, 2008 and 2007 (in thousands):
 
                         
    2009     2008     2007  
 
Realized gain (loss)
  $ 98,148     $ (6,388 )   $ 7,279  
Unrealized gain (loss)
    (50,026 )     72,533       (5,318 )
                         
Total gain from derivative financial instruments
  $ 48,122     $ 66,145     $ 1,961  
                         


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The following table summarizes the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of December 31, 2009: