QELP Quest Energy Partners, L.P. (MM)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number: 001-33787

QUEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

(405) 600-7704

(Registrant’s telephone number, including area code)

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
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 Section 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The registrant’s common units were not publicly traded as of the last business day of the registrant’s most recently completed second fiscal quarter. The aggregate market value of the common units of the registrant held by non-affiliates computed by reference to the $14.55 closing price of such common units on March 25, 2008, was approximately $132,405,000. As of March 25, 2008, the registrant had 12,301,521 common units and 8,857,981 subordinated units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None.

 

 

TABLE OF CONTENTS

 

GUIDE TO READING THIS REPORT

 

As used in this report, unless we indicate otherwise:

 

 

In this report we also use some oil and natural gas industry terms that are defined under the caption “Glossary of Selected Terms” at the end of Items 1 and 2 of this report.

 

 

Overview

 

We are a Delaware limited partnership formed in July 2007 by our Parent to acquire, exploit and develop oil and natural gas properties. Effective November 15, 2007, we consummated the initial public offering of our common units and acquired the gas and oil properties contributed to us by our Parent in connection with that offering. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders at our initial distribution rate and, over time, to increase our quarterly cash distributions. Our operations currently are focused on the development of coal bed methane, or CBM, in a 15-county region in southeastern Kansas and northeastern Oklahoma, referred to in this report as the “Cherokee Basin.” In addition to our producing properties, we have a significant inventory of potential drilling locations and acreage in the Cherokee Basin that we believe will allow us to grow our reserves and production over time.

 

We operate in one reportable segment engaged in the exploitation, development and production of gas and oil properties. As of December 31, 2007, our properties had 211.1 Bcfe of estimated net proved reserves, of which approximately 99% were CBM and 66.9% were proved developed. We operate over 99% of our existing wells, with an average net working interest of 99% and an average net revenue interest of approximately 82%. We believe we are the largest producer of natural gas in the Cherokee Basin with an average net daily production of 46.7 Mmcfe for the year ended December 31, 2007. Our estimated net proved reserves at December 31, 2007 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure,” of $322.5 million. Our reserves are long-lived, with an average proved reserve-to-production ratio of 12.3 years (8.12 years for our proved developed properties) as of December 31, 2007. Our typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

 

We have entered into derivative contracts with respect to approximately 80% of our estimated net production from proved developed producing reserves through the fourth quarter of 2010. The derivative contracts for 2008 cover approximately 58% of our total estimated net production for 2008. We also intend to diversify our operations by pursuing accretive acquisitions of conventional and unconventional gas and oil assets outside the Cherokee Basin.

 

As of December 31, 2007, we were operating approximately 2,254 gross gas wells, of which over 90% were multi-seam wells, and 29 gross oil wells. As of December 31, 2007, we owned the development rights to approximately 558,190 net acres throughout the Cherokee Basin and had only developed approximately 52% of our acreage. For 2008, we have budgeted approximately $41.0 million to drill and complete an estimated 325 gross wells and recomplete an estimated 52 gross wells, as well as an additional $37.5 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities. Our recompletions generally consist of converting wells that were originally completed with single seam completions into multi-seam completions, which allows us to produce additional gas from different levels. We expect to drill and connect 325 wells in 2008. At this time, we have identified our drilling locations for 2008 and many of these wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2007 reserve report. As of December 31, 2007, our undeveloped acreage contained approximately 2,100 gross CBM drilling locations, of which approximately 800 were classified as proved undeveloped. Over 99% of the CBM wells that have been drilled on our acreage to date have been successful. Our Cherokee Basin acreage is currently being developed utilizing primarily 160-acre spacing. However, several of our competitors are currently developing their CBM reserves in the Cherokee Basin on 80-acre spacing. We are currently conducting a pilot program to test the development of a portion of our acreage using 80-acre spacing. If our pilot project is successful, we could significantly increase the number of CBM drilling locations which are present on our acreage. None of our acreage or producing wells is associated with coal mining operations.

 

As of December 31, 2007, we had an inventory of approximately 212 drilled CBM wells awaiting connection to the gathering system of our affiliate, Quest Midstream. It is our intention to focus on the development of CBM reserves that can be immediately served by Quest Midstream’s gathering system.

The following chart reflects our organizational structure.

 

 

Recent Developments

 

Our Formation and IPO.   In July 2007, our Parent formed us to acquire, exploit and develop oil and natural gas properties. On November 15, 2007, our Parent transferred Quest Cherokee, LLC (which owned all of its Cherokee Basin gas and oil leases) and Quest Cherokee Oilfield Service, LLC (which owned all of its Cherokee Basin field equipment and vehicles) to us in exchange for 3,201,521 common units and 8,857,981 subordinated units and a 2% general partner interest. Also on November 15, 2007, we completed our initial public offering of 9,100,000 common units at $18.00 per unit, or $16.83 per unit after payment of the underwriting discount (excluding a structuring fee). Total proceeds from the sale of our common units in the initial public offering were $163.8 million, before underwriting discounts, a structuring fee and offering costs, of approximately $10.6 million, $0.4 million and $1.5 million, respectively. On November 9, 2007, our common units began trading on the NASDAQ Global Market under the symbol “QELP.”

 

Quest Energy GP, our general partner, was formed in July 2007. Quest Energy GP is a wholly-owned subsidiary of our Parent. Quest Energy GP owns 431,827 general partner units representing a 2% general partner interest in us and all of the incentive distribution rights. For more information regarding our initial public offering and related transactions, see our Current Reports on Form 8-K filed November 9 and November 21, 2007.

 

New Credit Agreement.   In connection with the closing of our initial public offering, on November 15, 2007, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”), as a guarantor, with our wholly-owned subsidiary, Quest Cherokee, as the borrower, our Parent, as the initial co-borrower, Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. Our Parent and Quest Cherokee had previously been parties to the following credit agreements with Guggenheim Corporate Funding, LLC (“Guggenheim”): (i) Amended and Restated Senior Credit Agreement, dated February 7, 2006, as amended; (ii) Amended and Restated Second Lien Term Loan Agreement, dated June 9, 2006, as amended; and (iii) Third Lien Term Loan Agreement, dated June 9, 2006, as amended (collectively, the “Prior Credit Agreements”). Guggenheim and the lenders under the Prior Credit Agreements assigned all of their interests and rights (other than certain excepted interests and rights) in the Prior Credit Agreements to RBC and the new lenders under the Credit Agreement pursuant to a Loan Transfer Agreement, dated November 15, 2007, by and among Quest Cherokee, our Parent, certain of our Parent’s subsidiaries, Guggenheim, Wells Fargo Foothill, Inc., the lenders under the Prior Credit Agreements and RBC. The Credit Agreement amended and restated the Prior Credit Agreements in their entirety.

The credit facility under the Credit Agreement consists of a five-year $250 million revolving credit facility. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by RBC and the lenders every six months taking into account the value of Quest Cherokee’s proved reserves. In addition, Quest Cherokee and RBC each have the right to initiate a redetermination of the borrowing base between each six-month redetermination. As of December 31, 2007, the borrowing base was $160 million, and the amount borrowed under the Credit Agreement was $94 million. At the closing of our initial public offering, our Parent was released as a borrower under the Credit Agreement.

 

For more information regarding the Credit Agreement, see Note 4. Long-Term Debt to the financial statements included in this Form 10-K.

 

Acquisition of Oil Producing Properties.   In early February 2008, we purchased 1,200 acres in Seminole County, Oklahoma from Landmark Energy for $9.5 million. We reduced our land budget for 2008 in a similar amount to retain our total capital budget unchanged. The oil producing properties have estimated reserves of 712,000 Bbl, all of which are proved developed producing.

 

Business Strategies

 

Our primary business objective is to make quarterly cash distributions to our unitholders at our initial distribution rate, and over time increase our quarterly cash distributions. Our strategy for achieving this objective is to:

 

 

Competitive Strengths

 

We believe that we are well positioned to achieve our primary business objective and to execute our strategies because of the following competitive strengths:

 

 

 

Our Relationship with Our Parent

 

One of our principal attributes is our relationship with our Parent, which is an independent energy company engaged in the exploration, development and production of gas and oil and related midstream activities. Our Parent controls us through its ownership of our general partner, which owns a 2% general partner interest in us as well as all of the incentive distribution rights. Our Parent also owns 3,201,521 common units and 8,857,981 subordinated units representing an aggregate 57% limited partner interest in us.

 

In connection with our initial public offering, we entered into the following agreements with our Parent:

 

Omnibus Agreement.   We, our general partner, and our Parent entered into an Omnibus Agreement, which governs our Parent’s and its affiliates relationship with us regarding the following matters:

 

 

 

Our Parent’s maximum liability for its environmental indemnification obligations will not exceed $5 million, and it will not have any indemnification obligation for environmental claims or title defects until our aggregate losses exceed $500,000.

 

Management Agreement.   We, our general partner, and Quest Energy Service, LLC, our Parent’s wholly-owned subsidiary (“Quest Energy Service”), entered into a Management Services Agreement, under which Quest Energy Service will perform acquisition services and general and administrative services, such as accounting, finance, tax, property management, risk management, land, marketing, legal and engineering to us, as directed by our general partner, for which we will reimburse Quest Energy Service on a monthly basis for the reasonable costs of the services provided.

 

While our relationship with our Parent may benefit us, it is also a source of potential conflicts of interest. Our Parent currently owns approximately 22,700 net undeveloped acres located in the States of Texas, Maryland, New Mexico and Pennsylvania. Part of our Parent’s strategy is to acquire additional acreage in areas without proved gas and oil reserves and to conduct exploration activities on its existing properties and any other properties acquired in the future. Our Parent currently intends to focus its exploration activities on areas with potential for producing unconventional gas.

 

For example, on February 6, 2008, our Parent entered into an amended and restated merger agreement with Pinnacle Gas Resources, Inc. or “Pinnacle” to acquire Pinnacle. Pinnacle is an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves and focuses on the development of CBM properties located in the Rocky Mountain Region. Pinnacle currently conducts its operations in the Powder River Basin and Green River Basin located in Montana and Wyoming. As of December 31, 2007, Pinnacle owned natural gas and oil leasehold interests in approximately 494,000 gross (316,000 net) acres, approximately 93% of which were undeveloped. It is anticipated that the closing of the merger will occur in the second quarter of 2008.

 

We believe that we may have opportunities to acquire from our Parent gas or oil properties with additional proved reserves that are appropriate to our structure and strategy as a master limited partnership. In addition, opportunities may arise to acquire a package of gas or oil properties, only some of which have proved reserves. In those cases, we anticipate that we and our Parent could work together to acquire all of the properties with our Parent acquiring those properties on which further exploration activities are required while we would acquire those properties that are suitable for exploitation and development activity. We believe our Parent will have a strong incentive to contribute or sell additional assets to us, and to team with us to acquire properties jointly, due to its significant ownership of limited and general partner interests in us. However, our Parent has no obligation to do so and may elect to acquire or dispose of gas and oil properties outside the Cherokee Basin in the future without offering us the opportunity to purchase or participate in the acquisition of those assets. Our Parent has retained such flexibility because it believes it is in the best interests of its shareholders to do so. We cannot say which, if any, opportunities to acquire assets from our Parent may be made available to us or if we will choose to pursue any such opportunity. Moreover, our Parent and its subsidiaries are not prohibited from competing with us outside the Cherokee Basin.

 

Description of Our 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.

 

We acquired the properties in the Cherokee Basin in the following transactions:

 

 

Characteristics of Coal Bed Methane.   The rock containing gas, referred to as “source rock,” is usually different from reservoir rock, which is the rock through which the 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. Coalbed 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.

 

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 coalbed 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 well bore 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.   Historically, we have developed our CBM reserves in the Cherokee Basin on 160-acre spacing. However, we are beginning to develop some test wells on 80-acre spacing. Our wells generally reach total depth in 1.5 days and our average cost for 2007 to drill and complete a well, excluding the related pipeline infrastructure, was approximately $124,000. We estimate that for 2008, our average cost for drilling and completing a well will be approximately $121,000, excluding the related pipeline infrastructure. We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has net reserves of 130 Mmcf. Our general production profile for a CBM well averages an initial production rate of 15-20 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 55-60 Mcf/d (net) follows the initial dewatering period for a period

of approximately twelve months. After 24 months, 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 also include an active program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. During the year ended December 31, 2007, we recompleted approximately 43 wellbores in Kansas and an additional 7 wellbores in Oklahoma and we had an additional 100 wellbores awaiting 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 $20,000 per well. Adding new zones to a 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 and the ultimate recoverable reserves available per well.

 

Wells are equipped with small pumping units to facilitate the dewatering of the producing coal seams. Generally, upon initial production, a single coal seam will produce 50-60 Bbls of water per day. A multi-seam completion produces about 150 Bbls of water per day. Eventually, water production subsides to 30-50 Bbls per day. Produced water is disposed through injection wells we drill into the underlying Arbuckle formation. One disposal well will generally handle the water produced from 25 producing wells.

 

Gas and Oil Data

 

Estimated Net Proved Reserves.   The following table presents our estimated net proved gas and oil reserves relating to our natural gas and oil properties as of the dates presented based on our reserve reports as of the dates listed below. The data was prepared by the petroleum engineering firm Cawley, Gillespie & Associates, Inc. in Ft. Worth, Texas. We filed estimates of our gas and oil reserves for the calendar years 2007, 2006 and 2005 with the Energy Information Administration of the U.S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the gas and oil volumes from our operated properties only, regardless of net interest. The difference between the gas and oil reserves reported on Form EIA-23 and those reported in this table exceeds 5%. The standardized measure values shown in the table are not intended to represent the current market value of our estimated gas and oil reserves.

 

 

 

 

The data in the table above represents estimates only. Gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of gas and oil that are ultimately recovered. See Item 1A — “Risk Factors — Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate.”

 

Production Volumes, Sales Prices and Production Costs.   The following table sets forth information regarding the natural gas and oil properties owned by us through our subsidiaries. The gas and oil production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.

 

Producing Wells and Acreage.   The following tables set forth information regarding our ownership of productive wells and total acres as of December 31, 2005, 2006 and 2007. For purposes of the table below, productive wells consist of producing wells and wells capable of production.

 

 

 

 

During the year ended December 31, 2007, we drilled 575 gross (571 net) new wells on our properties, all being gas wells. The wells drilled have been evaluated and were included in the year-end reserve report. The oil well count remains constant as we have been focused on adding gas reserves. See “— Drilling Activities.” During the year ended December 31, 2007, we continued to lease additional acreage in certain core development areas of the Cherokee Basin.

 

 

 

 

As of December 31, 2007, in the Cherokee Basin, we had 287,903 net developed acres and 270,287 net undeveloped acres. Developed acres are acres spaced or assigned to productive wells/units. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, 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. Most of the wells expected to be drilled in the next year will be of the development category and in the vicinity of Quest Midstream’s existing or planned construction pipeline network. Our drilling, recompletion, abandonment, and acquisition activities for the periods indicated are shown below (all wells are in the Cherokee Basin):

 

 

 

 

The 575 gross new natural gas wells completed for the year ended December 31, 2007 reflect an average activity level of approximately 48 gross wells per month. We plan to drill and complete an average of approximately 27 gross wells per month for year 2008, subject to capital being available for such expenditures.

 

During the period from December 31, 2007 through March 4, 2008, we drilled 73 gross wells and connected 65 gross wells. As of March 5, 2008, we were drilling 2 gross wells and approximately 140 gross wells were in the process of being completed.

 

Operations

 

General.   As the operator of wells in which we have an interest, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Quest Energy Service manages all of our properties and employs production and reservoir engineers, geologists and other specialists. Quest Cherokee Oilfield Service, LLC, our wholly-owned subsidiary, employs our Cherokee Basin field personnel.

 

Field operations conducted by our personnel include duties performed by “pumpers” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, 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.

 

We also provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third-party contractors, which typically provide these services. We believe this results in reduced delays in executing our plan of development. We are also able to realize significant cost savings because we can avoid paying price mark-ups and also because we are able to purchase our own supplies at bulk discounts.

We rely on third-party contractors to drill our wells. Once a well is drilled, either we or a third-party contractor will run the casing, and we will perform the cementing work. We also perform our own fracturing and stimulation work. Finally, we complete our own well site construction. We have our own fleet of 20 well service units that we use in the process of completing our wells, and also to perform remedial field operations required to maintain production from our existing wells.

 

Gas and Oil Leases.   As of December 31, 2007, we had over 4,350 leases covering approximately 558,190 net acres. The typical gas lease provides for the payment of royalties to the mineral owner for all gas produced from any well drilled on the lease premises. This amount ranges from 18.75% to 12.5% resulting in an 81.25% to 87.5% net revenue interest to us.

 

Because the acquisition of gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other gas and oil operators. In order to gain the right to drill these leases, we may purchase leases from other gas and oil operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 78.125% and 81.25%.

 

Approximately 75% of our gas and oil leases are held by production, which means that for as long as our wells continue to produce gas or oil, we will continue to own the lease.

 

Gas Gathering

 

We became a party to an existing midstream services and gas dedication agreement entered into on December 22, 2006, but effective as of December 1, 2006, between our Parent and Quest Midstream. Pursuant to the midstream services agreement, Quest Midstream gathers and provides certain midstream services, including, dehydration, treating and compression, to us for all gas produced from our wells in the Cherokee Basin that are connected to Quest Midstream’s gathering system.

 

The initial term of the midstream services agreement expires on December 1, 2016, with two additional five-year extension periods that may be exercised by either party upon 180 days’ notice. The fees charged under the midstream services agreement are subject to renegotiation upon the exercise of each five-year extension period.

 

Under the midstream services agreement, we agreed to pay Quest Midstream $0.50 per MMBtu of gas for gathering, dehydration and treating services and $1.10 per MMBtu of gas for compression services, subject to an annual adjustment to be determined by multiplying each of the gathering services fee and the compression services fee by the sum of (i) 0.25 times the percentage change in the producer price index for the prior calendar year and (ii) 0.75 times the percentage change in the Southern Star first of month index for the prior calendar year. Such adjustment will be calculated within 60 days after the beginning of each year, but will be retroactive to the beginning of the year. Such fees will never be reduced below the initial rates described above. For 2008, we anticipate the fees will be $0.51 per MMBtu of gas for gathering, dehydration and treating services and $1.13 per MMBtu of gas for compression services. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

 

In accordance with the midstream services agreement, we will bear the cost to remove and dispose of free water from our gas prior to delivery to Quest Midstream and of all fuel requirements necessary to perform the gathering and midstream services, plus any gas shrinkage.

 

Quest Midstream will have an exclusive option for sixty days to connect to its gathering system each of the gas wells that we develop in the Cherokee Basin. In addition, Quest Midstream will be required to connect to its gathering system, at its expense, any new gas wells that we complete in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. Quest Midstream also has the sole discretion to cease providing services on all or any part of its gathering system if it determines that continued operation is not economically justified. If Quest Midstream elects to do so, it must

provide us with 90 days’ written notice and will offer us the right to purchase that part of the terminated system. If we do acquire that part of the system and it remains connected to any other portion of Quest Midstream’s gathering system, then we may deliver our gas from the terminated system to Quest Midstream’s system, and a fee for any services provided by Quest Midstream will be negotiated.

 

In addition, Quest Midstream agreed to install the saltwater disposal lines for our gas wells connected to Quest Midstream’s gathering system for a fee of $1.25 per linear foot and connect such lines to our saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, we anticipate the fees will be $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to our saltwater disposal wells.

 

The midstream services agreement also requires the drilling of a minimum of 750 new wells in the Cherokee Basin during the two year period ending December 1, 2008, 575 of which have been drilled in the Cherokee Basin through December 31, 2007. We expect to drill 325 wells in 2008.

 

Marketing and Major Customers

 

We market our own natural gas. For the year ended December 31, 2007, approximately 79% of our gas was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”) and 21% was sold to Tenaska Marketing Ventures (“Tenaska”). For the period from November 15, 2007 through December 31, 2007, approximately 100% of our natural gas was sold to ONEOK. More than 95% of our natural gas was sold to ONEOK in 2006 and 2005. No other customer accounted for more than 10% of our consolidated revenues for the years ended December 31, 2007, 2006 and 2005.

 

Our oil is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, L.P. We do not have long term delivery commitments for our gas and oil production.

 

If we were to lose any of these gas and oil purchasers, we believe that we would be able to promptly replace the purchaser.

 

Hedging Activities

 

We seek to mitigate our exposure to volatility in commodity prices through our use of derivative contracts including fixed-price contracts comprised of energy swaps and collars. As of December 31, 2007, we had entered into derivative contracts with respect to approximately 80% of our total estimated net production from proved developed producing reserves through the fourth quarter of 2010. These fixed price swaps and collars cover 40% and 40%, respectively, of our estimated net gas production from proved developed producing reserves in 2008 or 29% and 29%, respectively, of our total estimated net production for 2008. In addition, for 2009 and 2010, these fixed price swaps cover 80% and 80%, respectively, of our estimated net gas production from proved developed producing reserves. By removing a significant portion of price volatility of our future gas production we have mitigated, but not eliminated, the potential effects of changing gas prices on our cash flows from operations for those periods. We sell the majority of our gas based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. All of these derivative contracts are based on the Southern Star first of month index, except for some of our older collar agreements covering approximately 2.9 Bcf of gas in 2008 (17% of our estimated net gas production from proved developed producing reserves) and fixed price swaps covering approximately 4.8 Bcf of gas in 2008 (27% of our estimated net gas production from proved developed producing reserves) that are based on NYMEX pricing. As a result, our derivative contracts do not expose us to basis differential risk, except for the NYMEX collars and swaps. As of December 31, 2007, we had entered into derivative contracts locking the basis differential on approximately 25% of these NYMEX volumes at a weighted average rate of approximately $1.09 per Mcf. For more information on our derivative contracts, see Note 6. Financial Instruments and Note 7. Derivatives, in the notes to the consolidated/carve out financial statements included in Item 8 of this report.

Competition

 

We operate in a highly competitive environment for acquiring properties, marketing gas and oil and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive gas and oil 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 gas and oil industry. None of our Parent or any of its affiliates is restricted from competing with us outside the Cherokee Basin. Our Parent or its affiliates may acquire, invest in or dispose of assets outside the Cherokee Basin in the future without any obligation to offer us the opportunity to purchase or own interests in those assets.

 

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the gas and oil industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation program.

 

Competition is also strong for attractive gas and oil producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

 

Title to Properties

 

As is customary in the gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved 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 gas and oil 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 gas and oil 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 gas and oil 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 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 as described in this report.

 

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties, we have obtained gas and oil leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. Please read “Legal Proceedings” under Item 3 of this report.

Seasonal Nature of Business

 

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 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 knocked 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 gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for gas. Seasonal anomalies such as mild winters and hot summers sometimes lessen this fluctuation.

 

Environmental 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. These laws and regulations may, among other things:

 

 

These laws, rules and regulations may also restrict the rate of gas and oil production below the rate that would otherwise be possible. The regulatory burden on the gas and oil 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. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the gas and oil 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.

 

Waste Handling.   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, and production of gas and oil are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain gas and oil 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, that may be regulated as hazardous wastes.

Comprehensive Environmental Response, Compensation and Liability Act.   The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, 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 be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain 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 gas and oil exploration and production 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, remediate contaminated property, or perform plugging or pit closure operations to prevent future contamination.

 

Water Discharges.   The Clean Water Act, or 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 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, or 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 — in our case, the Oklahoma Corporation Commission and the Kansas Corporation Commission. 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.

 

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, or 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 toxic 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, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require gas and oil exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some gas and oil 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 regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Gas and oil 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. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

 

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as “greenhouse gases”, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol; however, Congress has recently considered proposed legislation directed at reducing “greenhouse gas emissions”, and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant”, which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in gas and oil exploration and production operations. The gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

 

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 .  Gas and oil exploration and production activities on federal lands 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, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of gas and oil projects.

 

Endangered Species Act.   The Endangered Species Act 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 OSH Act, 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 the 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, 2007. 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 2008. 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, results of operations or ability to make distributions to you.

 

Other Regulation of the Gas and Oil Industry

 

The gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the gas and oil 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 gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the gas and oil 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.

Drilling 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:

 

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of gas and oil 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, state conservation laws establish maximum rates of production from gas and oil wells, 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 gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes 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 gas and oil 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 law is unsettled in the State of Kansas as to who has the responsibility to plug such abandoned wells and the Kansas Corporation Commission, or KCC, issued a Show Cause Order in February 2007 requiring our operating company, Quest Cherokee, to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on land covered by a gas lease that is owned and operated by Quest Cherokee in Wilson County, Kansas, and upon which Quest Cherokee has drilled and is operating a gas well. Please read “Legal Proceedings” under Item 3 of this report.

 

Gas Marketing.   The availability, terms and cost of transportation significantly affect sales of gas. The interstate transportation and sale for resale of 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 Federal Energy Regulatory Commission or FERC. Federal and state regulations govern the price and terms for access to gas pipeline transportation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the gas industry, most notably interstate gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these regulatory changes to our gas marketing operations, and we note that some of the 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 gas marketers with which we compete.

 

The Energy Policy Act of 2005, or EP Act 2005, gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the Natural Gas Act of 1938, or 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 the FERC to up to $1,000,000 per day, per violation. In addition, the 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 gas or transportation service subject to the 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 the FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

 

Although gas prices are currently unregulated, FERC promulgated regulations in December 2007 requiring natural gas sellers to submit an annual report, beginning in May 2009, reporting certain information regarding natural gas purchases and sales ( e.g. , total volumes bought and sold, volumes bought and sold and index prices, etc.). Additionally, Congress historically has been active in the area of gas regulation. We cannot predict whether new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress 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 Regulation.   The various states regulate the drilling for, and the production, gathering and sale of, gas and oil, including imposing severance taxes and requirements for obtaining drilling permits. For example, Kansas currently imposes a severance tax on the gross value of gas and oil 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 gas and oil conservation assessments per barrel of oil and per 1,000 cubic feet of gas produced. In general, gas and oil leases and gas and oil 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 gas and oil produced. Oklahoma also imposes an excise tax based on the gross value of gas and oil produced. All property used in the production of gas and oil 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.

 

States may regulate rates of production and may establish maximum daily production allowables from gas and oil wells based on market demand or resource conservation, or both. 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 be to limit the amounts of gas and oil that may be produced from our wells and to limit the number of wells or locations we can drill.

 

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 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 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.

 

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

 

At March 1, 2008, we employed approximately 250 field employees that perform development and maintenance services on our wells. We entered into a management services agreement with Quest Energy Service, LLC pursuant to which it performs administrative services for us such as accounting, finance, land, legal and engineering. We also have access to Quest Energy Service’s personnel and senior management team and access to its operational, commercial, technical, risk management and administrative infrastructure. Quest Energy Service has an experienced staff of approximately 60 executive and administrative personnel. None of these employees are represented by labor unions or covered by any collective bargaining agreement. Quest Energy Service and our general partner believe that relations with these employees are satisfactory.

 

Administrative Facilities

 

Our principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102, which is also where our Parent’s principal executive offices are located. Our Parent leases this office space, and the lease covers approximately 35,000 square feet with annual rental costs of approximately $631,000. The lease is for 10 years expiring in August 31, 2017.

 

We own a building located at 211 West 14th Street in Chanute, Kansas 66720 that we use as an administrative office, an operations terminal and a repair facility. We own an additional building on Johnson Road for field offices. An office building at 127 West Main in Chanute, Kansas is owned and operated by us as a geological laboratory.

 

Available Information

 

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, or Exchange Act, are made available free of charge on our website at www.qelp.net as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available at the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and Ethics and the charter of the audit committee of the board of directors of our general partner. No information from either the SEC’s website or our website is incorporated herein by reference.

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 Form 10-K.

 

Bbl.   One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

Bbl/d.   One Bbl 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.

 

Btu or 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.

 

Developed acreage.   The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well.   A well drilled within the proved boundaries of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole or 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.

 

Eligible Holder.   A person or entity qualified to hold an interest in gas and oil leases on federal lands. As of the date hereof, an Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

 

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.

 

Exploratory well.   A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

 

Field.   An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

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.

 

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.

 

MMBtu.   One million British thermal units.

 

MMcf.   One million cubic feet of gas.

 

MMcf/d.   One MMcf per day.

 

MMcfe.   One Mcf equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

Mmcfe/d.   One Mmcfe 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.   The combination of ethane, propane, butane and natural gasolines 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 ease of movement of water and/or gases through a soil material.

 

Perforation.   The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

 

Productive well.   A well that produces commercial quantities of hydrocarbons exclusive of its capacity to produce at a reasonable rate of return.

 

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. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at http://www.sec.gov/about/forms/regs-x.pdf.

 

Proved reserves.   The estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at http://www.sec.gov/about/forms/regs-x.pdf.

 

Proved undeveloped reserves or PUDs.   Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at www.sec.gov/about/forms/regs-x.pdf.

 

Recompletion.   The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve.   That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

Reserve-to-production ratio.   This ratio is calculated by dividing estimated net proved reserves by the production from the previous year to estimate the number of years of remaining production.

 

Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

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.

 

Shut in.   Stopping an oil or gas well from producing.

 

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. Our standardized measure does not reflect any future income tax expenses because we are not subject to federal income taxes. Our standardized measure differs from the standardized measure presented in the historical audited financial statements of the Predecessor included in this report due to the exclusion of future income tax expense. 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.

 

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.

 

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. The following risk factors should be carefully considered together with all of the other information included in this report. If any of the following risks and uncertainties described below or elsewhere in this report were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

 

Risks Related to Our Business

 

We may not have sufficient cash flow from operations to pay quarterly distributions on our common units following the establishment of cash reserves and the payment of fees and expenses, including reimbursements of expenses to our general partner and its affiliates.

 

We may not have sufficient available cash flow from operations each quarter to pay the initial quarterly distribution of $0.40 per common unit following establishment of cash reserves and payment of fees and expenses,

including payments to our general partner and its affiliates. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. Further, our credit facility contains, and future debt agreements may contain, restrictions on our ability to pay distributions. We intend to reserve a substantial portion of our cash generated from operations to develop our gas properties and to acquire additional gas and oil properties in order to maintain and grow our level of reserves. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on numerous factors, including, among other things:

 

 

As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the minimum quarterly distribution amount. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Cash Distributions to Unitholders” under Item 5 of this report.

 

Gas prices are at relatively high levels and are very volatile, and if commodity prices decline significantly for a temporary or prolonged period, our cash flow from operations will decline and we may have to lower our quarterly distributions or may not be able to pay distributions at all.

 

Our revenue, profitability and cash flow depend upon the prices and demand for gas and oil, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will reduce the value of our reserves, our cash flow, our ability to borrow money or raise capital and our ability to pay distributions. Gas prices have been at high levels over the past several years when compared to prior years. The gas market is very volatile, and we cannot predict future gas prices. Prices for gas may fluctuate widely in response to relatively minor changes in the supply of and demand for gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

 

 

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX spot price ranged from a high of $18.41 per MMBtu to a low of $1.97 per MMBtu. During the year ended December 31, 2007, the NYMEX monthly gas index price (last day) ranged from a high of $7.59156 per MMBtu to a low of $5.445 MMBtu. If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.

 

Future price declines may result in a write-down of our asset carrying values.

 

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in gas prices would render a significant number of our planned exploitation 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 gas properties for impairments. We are 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, for the year ended December 31, 2006, we had an impairment charge of $30.7 million. Based on the low natural gas prices on December 31, 2007, we would have incurred a non-cash impairment loss of approximately $14.9 million for the quarter ended December 31, 2007. However, under the SEC’s accounting guidance in Staff Accounting Bulletin Topic 12(D)(e), if natural gas prices increase sufficiently between the end of a period and the completion of the financial statements for that period to eliminate the need for an impairment charge, an issuer is not required to recognize the non-cash impairment loss in its financial statements for that period. As of March 1, 2008, natural gas prices had improved sufficiently to eliminate the need for an impairment loss at December 31, 2007 and as a result, no impairment loss is reflected in our financial statements for the year ended December 31, 2007. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

 

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our cash from operations and our ability to make cash distributions to our unitholders.

 

Producing gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production as a consequence of the dewatering process. Our future gas reserves, production, cash flow and ability to make distributions depend on our success in developing and exploiting our current 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, which would adversely

affect our business, financial condition and results of operations and reduce cash available for distribution. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale.

 

As of December 31, 2007, our proved reserve-to-production ratio was 12.3 years (8.12 years for our proved developed properties). Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The reserve-to-production ratio reflected in our reserve report of December 31, 2007 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

 

We will not be able to sustain distributions at the current level without making accretive acquisitions or capital expenditures that maintain or grow our asset base. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.

 

We will not be able to sustain distributions at the current level without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient capital expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.

 

If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your investment, which would lower the return on your investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and therefore will be unable to raise the level of future distributions.

 

If our Parent fails to present us with, or successfully competes against us for, attractive acquisition opportunities, we may not be able to replace or increase our reserves, which would adversely affect our cash from operations and our ability to make cash distributions.

 

We rely upon our Parent and its affiliates to identify and evaluate for us prospective oil and natural gas properties for acquisition. Our Parent and its affiliates are not obligated to present us with potential acquisitions, and are not restricted from competing with us for potential acquisitions outside the Cherokee Basin. Because our Parent controls our general partner, we will not be able to pursue or consummate any acquisition opportunity unless our Parent causes us to do so. Further, we may be unable to make acquisitions because:

 

 

If our Parent and its affiliates fail to present us with, or successfully compete against us for, potential acquisitions, we may not be able to adequately maintain our asset base, which would adversely affect our cash from operations and our ability to make cash distributions.

To fund our growth capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof.

 

Use of cash generated from operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.

 

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on our profitability.

 

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

 

If we do not make acquisitions on economically acceptable terms, our future growth and ability to sustain or increase distributions will be limited.

 

Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. 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, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

 

Our operations require substantial capital expenditures to increase our asset base, which will reduce our cash available for distribution.

 

In order to increase our asset base, we will need to make substantial capital expenditures for the exploitation, development, production and acquisition of gas and oil reserves. These capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. Management currently estimates that it will require capital investments of approximately $41.0 million to drill and complete an estimated 325 gross wells for 2008, and recomplete an estimated 52 gross wells in 2008. Management also currently estimates that it will require capital investments of approximately $37.5 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities for 2008. These expenditures could increase as a result of:

 

 

 

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

 

If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other securities. Such uses of cash from operations will reduce cash available for distribution to our unitholders.

 

The credit facility of our operating subsidiary, Quest Cherokee, (to which we are a guarantor) has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

 

The operating and financial restrictions and covenants in the credit facility restricts our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. The credit facility restricts our ability to:

 

 

We also are required to comply with certain financial covenants and ratios. The credit facility requires us to maintain a leverage ratio (the ratio of our consolidated funded debt to our adjusted consolidated EBITDA, as defined by the credit facility) of less than 3.50 to 1.00 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. The credit facility requires us to maintain an interest coverage ratio (the ratio of our adjusted consolidated EBITDA to our consolidated interest charges, as defined by the credit facility) of not less than 2.50 to 1.00 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. The credit facility requires us to maintain a current ratio (the ratio of our consolidated current assets plus unused availability under our borrowing base to our consolidated current liabilities excluding non-cash obligations, asset and asset retirement obligations and current maturities of indebtedness) of not less than 1.00 to 1.00. In the past, our Parent has not satisfied all of the financial covenants and ratios contained in its credit facilities. In January 2005, our Parent determined that it was not in compliance with the leverage and interest

coverage ratios under a prior secured credit agreement and, in connection with a February 2005 amendment to such credit agreement, our Parent was unable to drill any additional wells until its gross daily production reached certain levels. Our Parent was unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, our Parent undertook a significant recapitalization that included a private placement of its common stock and the refinancing of its credit facilities. For the quarter ended March 31, 2007, our Parent was not in compliance with the maximum total debt to EBITDA ratio, and our Parent obtained a waiver of this default from its lenders. The credit facility generally permits us to pay distributions of available cash so long as we are in compliance with the provisions of the credit facility. A default under the credit facility similar to those experienced by our Parent in the past would have precluded us from making any distributions during the periods in which such defaults occurred.

 

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in the credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment 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 addition, our obligations under the credit facility are secured by substantially all of our assets, and if we are unable to repay the indebtedness under the credit facility, the lenders could seek to foreclose on our assets.

 

The credit agreement limits the amount we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) within 90 days 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 5% of the borrowing base. Additionally, if the lenders’ exposure under letters of credit exceeds the borrowing base after all borrowings under the credit agreement have been repaid, we will be required to provide additional cash collateral.

 

We may incur substantial additional debt in the future to enable us to pay distributions to our unitholders, which may negatively affect our ability to execute on our business plan.

 

Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may be unable to pay a distribution at the minimum quarterly distribution rate or the then-current distribution rate without borrowing under the credit facility. Significant declines in our production or significant declines in realized gas prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

 

When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under the credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under the credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

 

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

 

We have the ability to incur debt, including under the credit facility, subject to borrowing base limitations in the credit facility. Our future indebtedness could have important consequences to us, including:

 

 

 

Our ability to service our indebtedness 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 current or future indebtedness, we will be forced to take actions such as reducing distributions, 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 effect any of these remedies on satisfactory terms or at all.

 

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 expend 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 production rate of 15-20 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 55-60 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.

 

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

 

Even if we do make acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit. Any acquisition involves potential risks, including, among other things:

 

 

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you 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.

 

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 our acquisitions do not generate increases in available cash per unit, our ability to make cash distributions to our unitholders could materially decrease.

 

Due to the vast majority of our current operations taking place in the Cherokee Basin, acquisitions outside of the Cherokee Basin will expose us to operational inefficiencies and new operational risks.

 

Acquisitions outside the Cherokee Basin will expose us to different operational risks due to potential differences, among others, in:

 

 

Our estimated proved 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.

 

It is not possible to measure underground accumulations of gas in an exact way. Gas reserve engineering requires subjective estimates of underground accumulations of gas and assumptions concerning future gas prices, production levels and operating and development costs. In estimating our level of gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

 

 

 

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of gas and oil 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. For example, if gas prices at December 31, 2007 had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of December 31, 2007 would have decreased by $125.2 million, from $322.5 million to $197.3 million and our proved reserves would have decreased by 10.8 Bcfe from 211.1 Bcfe to 200.1 Bcfe.

 

Our standardized measure is calculated using unhedged gas prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

 

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

 

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our gas properties also will be affected by factors such as:

 

 

The timing of both our production and our incurrence of expenses in connection with the development and production of 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 Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities , 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 gas industry in general.

 

Drilling for and producing gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations, and as a result, our ability to pay distributions to our unitholders.

 

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 can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

 

 

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of 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 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. Our Cherokee Basin acreage is currently being developed utilizing primarily 160-acre spacing. We are currently conducting a pilot program to test the development of a portion of our acreage using 80-acre spacing. There can be no assurance that this pilot program will be successful.

 

Our hedging activities could result in financial losses or reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

 

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of gas, we currently and may in the future enter into derivative arrangements for a significant portion of our gas production. We have entered into derivative contracts with respect to approximately 80% of our estimated net production from proved developed producing reserves through the fourth quarter of 2010. Because a significant portion of the estimated increase in our net production will come from the development of new wells, our derivative contracts cover a smaller percentage of our total estimated production. For example, the derivative contracts for 2008 cover approximately 58% of our total estimated net production for 2008. Our derivative instruments are subject to mark-to-market accounting treatment, and the change in fair market value of the instrument is reported in our statement of operations each quarter, which has resulted in and may in the future result in significant net losses. The extent of our commodity price exposure is related largely to the effectiveness and 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 gas prices. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in 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 direct commodity price exposure on the unhedged portion of our production volumes. Please read “Quantitative and Qualitative Disclosures about Market Risk” under Item 7A of this report.

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

 

 

Because of our lack of asset and geographic diversification, adverse developments in our operating area would reduce our ability to make distributions to our unitholders.

 

The vast majority of our assets are currently located in the Cherokee Basin. As a result, our business is disproportionately exposed to adverse developments affecting this region. 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 this region. Due to our lack of diversification in asset type and location, an adverse development in our business or this operating area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

The economic terms of the midstream services agreement may become unfavorable to us.

 

Under the midstream services agreement, we pay Quest Midstream, which is a party related to us, a fee for gathering, dehydration and treating services and a compression fee. These fees are subject to an annual upward adjustment in the event of increases in the producer price index and the market price for gas. If these fees increase at a faster rate than gas prices, our ability to make cash distributions to our unitholders may be adversely affected. Such fees are subject to renegotiation in connection with each of the two five year renewal terms, beginning after the initial term expires on December 1, 2016. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms. The renegotiated fees may not be as favorable to us as the initial fees. For 2008, the fees will be $0.51 per MMBtu of gas for gathering, dehydration and treating services and $1.13 per MMBtu of gas for compression services.

 

In addition, the midstream services agreement requires the drilling of a minimum of 750 new wells in the Cherokee Basin during the two year period ending December 1, 2008, 575 of which have been drilled in the Cherokee Basin through December 31, 2007. We expect to drill 325 wells in 2008. At this time, we have identified our drilling locations for 2008 and many of these wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2007 reserve report. We are required to drill these wells even if gas prices were to decline, or our costs were to increase, to the point that these wells were uneconomical for us to drill. We cannot assure you that any of the remaining new wells required to be drilled pursuant to the midstream services agreement will be economically favorable for us. For additional information regarding the midstream services agreement, please read “— Gas Gathering” under Item 1 of this report.

The gathering fees payable to Quest Midstream under the midstream services agreement in some cases could exceed the amount we are able to charge to royalty owners under our gas leases for gathering and compression.

 

Under the midstream services agreement we are required to pay fees for gathering, dehydration and treating services and fees for compression services to Quest Midstream for each MMBtu of gas produced from our wells in the Cherokee Basin. The terms of some of our existing gas leases may not, and the terms of some of the gas leases that we may acquire in the future may not, allow us to charge the full amount of these fees to the royalty owners under the leases. We currently have leases covering approximately 116,000 net acres that generally permit only deductions for compression expenses, subject to certain exceptions. With respect to our remaining leases, we believe that we have the right to charge our royalty owners their proportionate share of the full amount of the fees due under the midstream services agreement. However, on August 3, 2007, certain mineral interest owners filed a putative class action lawsuit against 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. To the extent that we are unable to charge the full amount of these fees to our royalty owners, it will reduce our net income and the cash available for distribution to our unitholders.

 

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

 

The gas and oil industry is intensely competitive with respect to acquiring prospects and productive properties, marketing gas and oil and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent gas and oil companies, and they not only drill for and produce gas and oil, 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 ours. These companies may be able to pay more for gas and oil 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 gas and oil industry. These larger companies may have a greater ability to continue drilling activities during periods of low 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, financial condition and ability to make cash distributions to our unitholders.

 

We may have difficulty managing growth in our business.

 

Because of the relatively small size of our business, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

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

 

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

 

 

 

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

 

In accordance with typical industry practice, we currently possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not 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, results of operations and ability to make distributions to our unitholders.

 

Any amounts that we are required to pay as a result of our pending legal proceedings may affect our ability to pay distributions.

 

We are currently a party to several pending legal proceedings arising out of the conduct of our business. Please read “Legal Proceedings” under Item 3 of this report for a description of our material legal proceedings. Our Parent and its affiliates have also been named as defendants in a number of these proceedings. We will be responsible for any judgments or settlements resulting from these legal proceedings and have agreed to indemnify our Parent and its affiliates for any liability they may incur as a result of these legal proceedings. Any amounts that we are required to pay as a result of these legal proceedings would reduce our cash available for distribution to our unitholders. Our estimated cash available for distribution for the twelve months ending December 31, 2008, as set forth in our cash distribution policy described under “ Cash Distributions to Unitholders” in Item 5 of this report assumes no amounts are required to be paid by us with respect to these proceedings.

 

The credit and risk profile of our Parent could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

The credit and business risk profiles of our Parent may be factors considered in our credit evaluations because our general partner controls our business activities, including our cash distribution policy and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our Parent including the degree of its financial leverage and any dependence on cash flow from us to service its indebtedness.

 

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our Parent, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of our Parent and its affiliates because of their ownership interest in and control of us and the strong operational links between our Parent and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters applicable to gas and oil exploitation and production operations.

 

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our gas and oil exploitation and production 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, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for damages as a result of environmental and other impacts. Please read “Environmental Matters and Regulation” under Item 1 of this report for more information.

 

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to our unitholders could be adversely affected. Please read “Environmental Matters and Regulation” under Item 1 of this report for more information.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our gas and oil exploitation, development and production operations are subject to complex and stringent laws, rules and regulations. In order to conduct our operations in compliance with these laws, rules and regulations, we must obtain and maintain numerous permits, licenses, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws, rules and regulations. In addition, our costs of compliance may increase if existing laws, rules and regulations are revised or reinterpreted, or if new laws, rules and regulations become applicable to our operations.

 

The Cherokee Basin has been an active gas and oil 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 law is unsettled in the State of Kansas as to who has the responsibility to plug such abandoned wells and the KCC has issued a Show Cause Order in February 2007 requiring our operating company, Quest Cherokee, to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on land covered by a gas lease that is owned and operated by Quest Cherokee in Wilson County, Kansas, and upon which Quest Cherokee has drilled and is operating a gas well. If it is ultimately determined that we are responsible for plugging all of the wells located on our leased acreage that were abandoned by former operators, the costs for plugging and abandoning those wells would increase our costs and decrease our cash available for distribution. At this time, we are unable to determine the total number of wells located on our leased acreage that have been abandoned by prior operators.

 

We may face unanticipated water disposal costs.

 

We are subject to regulation that restricts our ability to discharge water produced as part of our CBM gas production operations. Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore, and our ability to remove and dispose of sufficient quantities of water from the coal seam 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 fail 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:

 

 

Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production and reduce our cash available for distribution.

 

Higher gas and oil prices generally stimulate increased demand and result in increased wages for crews and personnel in our production operations. These types of shortages or wage increases could increase our costs and/or restrict or delay our ability to drill the wells and conduct the operations that we currently have planned. 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 reduce our revenue and cash available for distribution. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented, reducing our production and cash available for distribution.

 

We depend on two customers for sales of all of our gas. To the extent these customers reduce the volumes of gas they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline.

 

During the year ended December 31, 2007, we sold approximately 79% of our gas to ONEOK and 21% of our gas to Tenaska under sale and purchase contracts, which have indefinite terms 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. If either of these customers were to reduce the volume of gas it purchases from us, our revenue and cash available for distribution may decline to the extent we are not able to find new customers for our production.

 

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 reduce our ability to make distributions to our unitholders.

 

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

 

As of December 31, 2007, we held gas leases on approximately 164,869 net acres in the Cherokee Basin that are still within their original lease term and 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 4,928 net acres are scheduled to expire before December 31, 2008 and an additional 80,843 net acres are scheduled to expire before December 31, 2009. If our leases expire, we will lose our right to develop the related properties. We typically acquire a three-year primary term when the original lease is acquired, with an option to

extend the term for up to three additional years, if the primary three-year term reaches expiration without a well being drilled to establish production for holding the lease.

 

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 ability to pay distributions.

 

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2007, approximately 800 gross proved undeveloped drilling locations and approximately 1,300 additional gross potential drilling locations. These identified drilling locations represent a significant part of our future development drilling program for the Cherokee Basin. 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. In addition, no proved reserves are assigned to any of the approximately 1,300 potential drilling locations we have identified and therefore, there may exist 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 as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or 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 a gas or oil lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such gas or oil lease or leases would be lost. It is our practice, in acquiring gas and oil leases, or undivided interests in gas and oil leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Prior to drilling a gas or oil well, however, it is the normal practice in the gas and oil 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 gas or oil 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.

 

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained gas and oil leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells. For additional information regarding these legal proceedings, please read “Environmental Matters and Regulation” under Item 1 of this report and “Legal Proceedings” under Item 3 of this report.

We rely on our general partner and Quest Energy Service for our management. If our general partner or Quest Energy Service fails to or inadequately performs, our costs will increase and reduce our cash from operations and our ability to make cash distributions to you.

 

We rely on our general partner and Quest Energy Service for our management. We also expect that our general partner will provide us with assistance in hedging our production and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved gas and oil reserves. Our Parent and its affiliates have no obligation to present us with potential acquisitions outside the Cherokee Basin, and, if they fail to do so, we will need to either seek acquisitions on our own or retain a third party to seek acquisitions on our behalf. In the long term, without further acquisitions, we will not be able to replace or grow our reserves, which would reduce our cash from operations and our ability to make cash distributions to you.

 

We depend on a limited number of key management personnel, who would be difficult to replace.

 

Our operations and activities are dependent to a significant extent on the efforts and abilities of management and key employees of our Parent, including our Chief Executive Officer Jerry Cash, Chief Operating Officer David Lawler and Chief Financial Officer David Grose. We maintain no key person insurance for either Messrs. Cash, Lawler or Grose. The loss of any member of our management or other key employees could negatively impact our ability to execute our strategy.

 

The amount of cash distributions that we will be able to distribute to unitholders will be reduced by the costs associated with being a public company, other general and administrative expenses and reserves that our general partner believes prudent to maintain for the proper conduct of our business and for future distributions.

 

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including capital expenditures and the costs of being a public company and other operating expenses, and we may reserve cash for future distributions during periods of limited cash flows. The amount of cash we have available for distribution to our unitholders will be affected by our level of reserves and expenses, including the costs associated with being a public company.

 

If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

 

Our general partner has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. Although our general partner has implemented controls to prepare and review our financial statements, we cannot be certain that its efforts to develop and maintain its internal controls will be successful, that it will be able to maintain adequate controls over our financial processes and reporting in the future or that it will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our general partner’s internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which likely would have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

 

Our Parent controls our general partner, which conducts our business and manages our operations. Our Parent and its affiliates have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to your detriment.

 

Our Parent owns and controls our general partner. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our Parent. Some of our general partner’s directors and executive officers are directors or officers of our Parent and Quest Midstream. Therefore, conflicts of interest may arise between our Parent and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held under state law and restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

 

 

 

Each common unitholder is bound by the provisions in the partnership agreement, including the provisions discussed above.

 

We do not have any officers and rely solely on officers of our general partner and employees of our Parent and its affiliates for the management of our business.

 

None of the officers of our general partner are employees of our general partner. We have entered into a management services agreement with Quest Energy Service, pursuant to which Quest Energy Service operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land and engineering. Affiliates of our Parent conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to our Parent and Quest Midstream. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, our Parent and its affiliates. In the event that the Pinnacle acquisition is consummated, our Parent will substantially increase its operations, which could result in increased competition for the time and effort of such officers and employees. If the officers of our general partner and the employees of our Parent and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

 

Unitholders have limited voting rights, are not entitled to elect our general partner or the directors of our general partner.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or our general partner’s board of directors, and will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen by our Parent. Since our Parent also holds 57% of our aggregate outstanding common and subordinated units, the public unitholders will not have an ability to influence any operating decisions or to prevent us from entering into any transactions. Furthermore, the goals and objectives of our Parent and our general partner relating to us may not be consistent with those of a majority of the public unitholders.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

Unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2 / 3 % of all outstanding units (including units held by our general partner and its affiliates) voting together as a single class is required to remove the general partner. Our general partner and its affiliates own 57% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

 

Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

 

As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Our Parent may engage in competition with us.

 

Our Parent and its affiliates may engage in competition with us outside the Cherokee Basin. Pursuant to the omnibus agreement, our Parent and its subsidiaries agreed to give us a right to purchase any natural gas or oil wells or other natural gas or oil rights and related equipment and facilities that they acquire within the Cherokee Basin, but not including any midstream or downstream assets. Our Parent may acquire, develop or dispose of additional oil or gas properties or other assets outside of the Cherokee Basin in the future, without any obligation to offer us the opportunity to acquire any of those assets.

 

If our Parent does engage in competition with us it could have an adverse impact on our results of operations and ability to make distributions to our unitholders. For a description of the non-competition provisions of the omnibus agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Management Services Agreement,” in each case, under Item 13 of this report.

 

We are restricted from engaging in businesses other than the exploration and development of gas and oil.

 

We will be subject to the midstream omnibus agreement dated as of December 22, 2006, but effective as of December 1, 2006, among Quest Midstream, Quest Midstream’s general partner, Quest Midstream’s operating subsidiary and our Parent so long as we are an affiliate of our Parent and our Parent or any of its affiliates controls Quest Midstream. Except for certain limited exceptions, the midstream omnibus agreement restricts us from engaging in the following businesses (each of which is referred to in this report as a “Restricted Business”):

 

 

 

These provisions will limit our flexibility to diversify into businesses other than the exploration and development of oil and gas, which may limit our ability to enter into different and potentially more profitable lines of business, and thus, adversely affect our ability to make distributions to our unitholders.

 

Our general partner has incentive distribution rights, which may incentivize it to cause us to distribute cash needed to develop our properties.

 

Our general partner has all of the incentive distribution rights entitling it to receive up to 23% of our cash distributions above certain target distribution levels in addition to its 2% general partner interest. This increased sharing in our distributions creates a conflict of interest for the general partner in determining whether to distribute cash to our unitholders or reserve it for reinvestment in the business and whether to borrow to pay distributions to our unitholders. Our general partner may have an incentive to distribute more cash than it would if its only economic interest in us were its 2% general partner interest. Furthermore, because of the commodity price sensitivity of our business, the general partner may receive incentive distributions due solely to increases in commodity prices as opposed to growth through development drilling or acquisitions.

 

Each quarter our general partner is required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

 

Our partnership agreement requires our general partner to deduct our estimated, rather than actual, maintenance capital expenditures from operating surplus each quarter in an effort to reduce fluctuations in operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the conflicts committee at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term, including on the general partner’s incentive distribution rights, but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for our previous underestimation.

 

Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

 

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, as determined by our general partner. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Payments for these services will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Management Services Agreement,” in each case, under Item 13 of this report.

 

Our general partner’s interest in us and control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does

not restrict the ability of the owner of our general partner from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers of our general partner.

 

We may issue additional units, including units that are senior to the common units, without approval of our unitholders, which would dilute the existing ownership interests of our unitholders.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

 

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

 

In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

The NASDAQ Global Market does not require a listed limited partnership like us to comply with some of its listing requirements with respect to corporate governance requirements.

 

Because we are a limited partnership, the NASDAQ Global Market does not require us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, you will not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.

 

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

 

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

 

 

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our general partner and its affiliates own approximately 26% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 57% of our aggregate outstanding common units.

 

The liability of our unitholders may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Kansas and Oklahoma. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have

not been clearly established in some of the other states in which we may do business. Our unitholders could be liable for any and all of our obligations as if they were a general partner if a court or government agency determined that:

 

 

Unitholders may have liability to repay distributions.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Sections 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are not liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

 

Common units held by persons who are not Eligible Holders will be subject to the possibility of redemption.

 

If we become subject to U.S. laws with respect to the ownership interests in oil and gas leases on federal lands, our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are Eligible Holders. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States, (2) a corporation organized under the laws of the United States or of any state thereof, (3) a public body, including a municipality or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. If these certification procedures are implemented, unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not receive distributions or allocations of income and loss on their units, and we will have the right to redeem the common units held by persons or entities who are not Eligible Holders at the then-current market price of the units. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

If we distribute cash from capital surplus, which is analogous of a return of capital, our minimum quarterly distribution rate will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

 

Our cash distribution will be characterized as coming from either operating surplus or capital surplus. Operating surplus generally means amounts we receive from operating sources, such as sale of our gas and oil production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98% to our unitholders and 2% to our general

partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner.

 

Our partnership agreement allows us to add to operating surplus up to $25.9 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to our general partner as the holder of the incentive distribution rights, rather than to holders of common units as a return of capital.

 

An increase in interest rates may cause the market price of our common units to decline.

 

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by any state will reduce the cash available for distribution to unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute. As a result, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will reduce our cash available for distribution and thus will be borne indirectly by our unitholders and our general partner.

 

Tax gain or loss on disposition of our common units could be more or less than expected.

 

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. If our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. If the IRS successfully contests some tax positions we take, unitholders could recognize more gain on the sale of units than would be the case if those positions were sustained, without the benefit of decreased income in prior years.

 

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file

United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

 

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audits of, and adjustments to, unitholders’ tax returns.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our subordinated and common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. If this occurs, you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated and for future years as a percentage of the cash distributed to you with respect to such periods. Although the amount of the increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

 

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the holders of incentive distribution rights and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the holders of the incentive distribution rights. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the holders of the incentive distribution rights, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the holders of the incentive distribution rights and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

Unitholders likely will be subject to state and local taxes and return filing requirements.

 

In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various

jurisdictions in which we conduct business or own property, now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in Kansas and Oklahoma. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder’s responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

 

None.

Item 3.    Legal Proceedings.   

 

Quest Cherokee and our indirectly owned subsidiary, Quest Cherokee Oilfield Service, LLC, are currently parties to various legal and governmental proceedings arising out of our operations in the normal course of business. The following is a summary of our material legal proceedings:

 

Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc., Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc. (now STP Cherokee, LLC) have been named Defendants in a lawsuit filed by Plaintiffs, Eddie R. Hill, et al . in the District Court for Craig County, Oklahoma (Case No. CJ-2003-30). Plaintiffs are royalty owners who are alleging underpayment of royalties owed to them. Plaintiffs also allege, among other things, that Defendants have engaged in self-dealing and breached fiduciary duties owed to Plaintiffs, and that Defendants have acted fraudulently toward the Plaintiffs. Plaintiffs also allege that the gathering fees and related charges should not be deducted in paying royalties. Plaintiffs’ claims relate to a total of 84 wells located in Oklahoma and Kansas. Plaintiffs are seeking unspecified actual and punitive damages. Defendants intend to defend vigorously against Plaintiffs’ claims.

 

STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service, LLC (improperly named Quest Energy Services, LLC) have been named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick and Suzan M. Kirkpatrick in the District Court for Craig County (Case No. CJ-2005-143). Plaintiffs allege that STP, Inc., et al. , sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs further allege that Defendants failed to include deductions on the check stubs of Plaintiffs in violation of state law and that Defendants deducted for items other than compression in violation of the lease terms. Plaintiffs assert claims of actual and constructive fraud and further seek an accounting stating that if Plaintiffs have suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover those damages. Plaintiffs have not quantified their alleged damages. Discovery is ongoing and Defendants intend to defend vigorously against Plaintiffs’ claims.

 

Quest Cherokee Oilfield Services, LLC has been named in this lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso in the District Court of Oklahoma County, Oklahoma (Case No. CJ-2007-11079). Plaintiffs allege that Plaintiff Segundo Trigoso was injured while working for Defendant on September 29, 2006 and that such injuries were intentionally caused by Defendant. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Defendant intends to defend vigorously against Plaintiffs’ claims.

 

Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest

Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee intends to defend vigorously against these claims.

 

Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery is ongoing. Quest Cherokee intends to defend vigorously against these claims.

 

Quest Cherokee was named as a defendant in a lawsuit (Case No. 05 CV 41) filed by Labette Energy, LLC in the District Court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas gathering pipeline in Labette County, Kansas, and that Quest Cherokee used that pipeline without plaintiff’s consent. Plaintiff also contends that the defendants slandered its alleged title to that pipeline and suffered damages from the cancellation of their proposed sale of that pipeline. Plaintiff claims that they were damaged in the amount of $202,375. Discovery in that case is ongoing and Quest Cherokee intends to defend vigorously against the plaintiff’s claims.

 

Quest Cherokee is a counterclaim defendant in a lawsuit (Case No. 2006 CV 74) filed by Quest Cherokee in District Court of Labette County, Kansas. Quest Cherokee filed that lawsuit seeking a declaratory judgment that several oil and gas leases owned by Quest Cherokee are valid and in effect. In the counterclaim, defendants allege that those leases have expired by their terms and have been forfeited by Quest Cherokee. Defendants seek a declaration that those leases are null and void, statutory damages of $100, and their attorney’s fees. Discovery in that case is ongoing. Quest Cherokee intends to vigorously defend against those counterclaims.

 

Quest Cherokee was named as a defendant in a class action lawsuit (Case No. 07-1225-MLB) 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. Discovery in that case is ongoing. Quest Cherokee intends to defend vigorously against these claims.

 

Quest Cherokee has been named as a defendant in several lawsuits in which the plaintiff claims that an oil and gas lease owned and operated by Quest Cherokee has either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits are pending in the District Courts of Labette, Montgomery, and Wilson Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of February 28, 2008, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,090 acres. Discovery in those cases is ongoing. Quest Cherokee intends to vigorously defend against those claims.

 

Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC has ordered Quest

Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas. Quest Cherokee denies that it is legally responsible for plugging the wells in issue and intends to vigorously defend against the KCC’s claims.

 

From time to time, we may be subject to legal proceedings and claims that arise in the ordinary course of our business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations. Like other natural gas and oil 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.

 

 

No matter was submitted to a vote of the holders of our units during the fourth quarter of 2007.

PART II

 

 

Market Information

 

Our common units began trading on the NASDAQ Global Market under the symbol “QELP” commencing with our initial public offering on November 9, 2007. The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for 2007:

 

 

 

 

Record Holders

 

At the close of business on March 25, 2008, based upon information received from our transfer agent and brokers and nominees, we had five (5) common unitholders of record. This number does not include owners for whom common units may be held in “street” names.

 

Cash Distributions to Unitholders

 

We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our cash distribution policy is subject to restrictions on distributions under our credit facility. Our credit facility contains material financial tests and covenants that we must satisfy.

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter:

 

 

 

 

 

Our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation. The general partner’s 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.46 per unit per quarter.

 

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution of $0.40 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

 

The subordination period will extend until the first day of any quarter beginning after December 31, 2012 that each of the following tests are met:

 

 

When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

 

 

If the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, 25% of the subordinated units will convert into an equal

number of common units. Similarly, if those tests are also satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2011, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

 

In addition to the early conversion of subordinated units described above, all of the subordinated units will convert into an equal number of common units on the first day of any quarter beginning after December 31, 2010 that each of the following tests are met:

 

 

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

 

Securities Authorized For Issuance Under Equity Compensation Plans

 

We have one equity compensation plan for our employees, consultants and non-employee directors pursuant to which unit awards may be granted. No awards were granted under our long-term incentive plan in 2007. The following is a summary of the common units remaining available for future issuance under such plan as of December 31, 2007:

 

 

For a description of our equity compensation plan, please see the discussion under Item 11 of this report.

 

Unregistered Sales of Equity Securities

 

In connection with our formation in July 2007, we issued a 2% general partnership interest to our general partner for $20 and a 98% limited partnership interest to our Parent for $980. Our Parent contributed $1,000 to our general partner in exchange for 100% of the member interests in our general partner. In connection with the closing of our initial public offering on November 15, 2007, we issued (i) 3,201,521 common units and 8,857,981 subordinated units to our Parent in exchange for its contribution of its ownership interest in Quest Cherokee to us, and (ii) 431,827 general partner units and incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) to our general partner in exchange for its contribution of its ownership interest in Quest Cherokee to us. Each subordinated unit will convert into one common unit as described above. Each of these transactions was exempt from registration under Section 4(2) of the Securities Act of 1933. There were no other sales of our unregistered securities during 2007.

 

Purchases of Equity Securities

 

There were no purchases of our common units made by or on behalf of us or certain affiliated purchasers during the fourth quarter of 2007.

 

 

The following table sets forth selected consolidated financial data of us and the Predecessor for the periods and as of the dates indicated. The selected financial data for the period from November 15, 2007 through December 31, 2007 are derived from our audited financial statements. The selected financial data for the period from January 1, 2007 through November 14, 2007 and as of November 14, 2007 and for the years ended and as of December 31, 2006 and 2005, the seven month transition period ended December 31, 2004 and the fiscal years ended May 31, 2004 and 2003 are derived from the audited financial statements of the Predecessor. The data are derived from our audited consolidated/carve out financial statements revised to reflect the reclassification of certain items. Comparability between years is affected by (1) changes in the annual average prices for oil and gas, (2) increased production from drilling and development activity, (3) significant acquisitions that were made during the fiscal year ended May 31, 2004, (4) the change in the fiscal year end on December 31, 2004, and (5) our initial public offering effective November 15, 2007.

 

The selected financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our consolidated/carve out financial statements, including the notes, appearing in Items 7 and 8 of this report.